10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2019

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

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.

PNM Resources, Inc. (“PNMR”)	YES	ü	NO
Public Service Company of New Mexico (“PNM”)	YES	ü	NO
Texas-New Mexico Power Company (“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 every Interactive Data File required to be submitted 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 such files).

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

Indicate by check mark whether 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		Smaller reporting company	Emerging growth company
PNMR		ü
PNM					ü
TNMP					ü

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 any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES   NO ü

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of each class	Trading Symbol(s)	Name of exchange on which registered
PNM Resources, Inc.	Common Stock, no par value	PNM	New York Stock Exchange

As of May 3, 2019, 79,653,624 shares of common stock, no par value per share, of PNMR were outstanding.

The total number of shares of common stock of PNM, no par value per share, outstanding as of May 3, 2019 was 39,117,799 all held by PNMR (and none held by non-affiliates).

The total number of shares of common stock of TNMP, $10 par value per share, outstanding as of May 3, 2019 was 6,358 all held indirectly by PNMR (and none held by non-affiliates).

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

This combined Form 10-Q 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-Q 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-Q that relate to each other registrant are not incorporated by reference therein.

2

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

INDEX

	Page No.
GLOSSARY	4
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
PNM RESOURCES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	8
Condensed Consolidated Statements of Comprehensive Income	9
Condensed Consolidated Statements of Cash Flows	10
Condensed Consolidated Balance Sheets	12
Condensed Consolidated Statement of Changes in Equity	14
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	15
Condensed Consolidated Statements of Comprehensive Income	16
Condensed Consolidated Statements of Cash Flows	17
Condensed Consolidated Balance Sheets	19
Condensed Consolidated Statement of Changes in Equity	21
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	22
Condensed Consolidated Statements of Cash Flows	23
Condensed Consolidated Balance Sheets	24
Condensed Consolidated Statement of Changes in Common Stockholder's Equity	26
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	83
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	116
ITEM 4. CONTROLS AND PROCEDURES	118
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	118
ITEM 1A. RISK FACTORS	119
ITEM 6. EXHIBITS	119
SIGNATURE	121

3

GLOSSARY

Definitions:
2014 IRP	PNM’s 2014 IRP
2017 IRP	PNM’s 2017 IRP
ABCWUA	Albuquerque Bernalillo County Water Utility Authority
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
AMI	Advanced Metering Infrastructure
AMS	Advanced Meter System
AOCI	Accumulated Other Comprehensive Income
APS	Arizona Public Service Company, the operator and a co-owner of PVNGS and Four Corners
ASU	Accounting Standards Update
August 2016 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
Board	Board of Directors of PNMR
BSER	Best system of emission reduction technology
BTMU	MUFG Bank Ltd., formerly the Bank of Tokyo-Mitsubishi UFJ, Ltd.
BTMU Term Loan	NM Capital’s $125.0 Million Unsecured Term Loan
CAA	Clean Air Act
Casa Mesa Wind	Casa Mesa Wind Energy Center
CCN	Certificate of Convenience and Necessity
CCR	Coal Combustion Residuals
CIAC	Contributions in Aid of Construction
CO2	Carbon Dioxide
CSA	Coal Supply Agreement
DC Circuit	United States Court of Appeals for the District of Columbia Circuit
December 2018 Compliance Filing	PNM’s December 31, 2018 filing with the NMPRC regarding SJGS
DOE	United States Department of Energy
DOI	United States Department of Interior
EGU	Electric Generating Unit
EIM	California Independent System Operator Western Energy Imbalance Market
EIS	Environmental Impact Study
EPA	United States Environmental Protection Agency
ESA	Endangered Species Act
ETA	The New Mexico Energy Transition 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
Four Corners	Four Corners Power Plant
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
IRP	Integrated Resource Plan

4

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.
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
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
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
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
PNM	Public Service Company of New Mexico and Subsidiaries
PNM 2017 New Mexico Credit Facility	PNM’s $40.0 Million Unsecured Revolving Credit Facility
PNM 2017 Term Loan	PNM’s $200.0 Million Unsecured Term Loan
PNM 2019 Term Loan	PNM’s $250.0 Million Unsecured Term Loan

5

PNM Revolving Credit Facility	PNM’s $400.0 Million Unsecured Revolving Credit Facility
PNMR	PNM Resources, Inc. and Subsidiaries
PNMR 2015 Term Loan	PNMR’s $150.0 Million Three-Year Unsecured Term Loan that matured on March 9, 2018
PNMR 2016 One-Year Term Loan	PNMR’s $100.0 Million One-Year Unsecured Term Loan that matured on December 14, 2018
PNMR 2016 Two-Year Term Loan	PNMR’s $100.0 Million Two-Year Unsecured Term Loan that matured on December 21, 2018
PNMR 2018 One-Year Term Loan	PNMR’s $150.0 Million One-Year Unsecured Term Loan
PNMR 2018 Two-Year Term Loan	PNMR’s $50.0 Million Two-Year Unsecured Term Loan
PNMR Development	PNMR Development and Management Company, an unregulated wholly-owned subsidiary of PNMR
PNMR Development Revolving Credit Facility	PNMR Development’s $25.0 million Unsecured Revolving Credit Facility
PNMR Development Term Loan	PNMR Development’s $90.0 Million Unsecured Term Loan
PNMR Revolving Credit Facility	PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan	PNMR’s $150.0 Million One-Year Unsecured Term Loan that matured on December 21, 2016
PPA	Power Purchase Agreement
PSD	Prevention of Significant Deterioration
PUCT	Public Utility Commission of Texas
PV	Photovoltaic
PVNGS	Palo Verde Nuclear Generating Station
RCRA	Resource Conservation and Recovery Act
RCT	Reasonable Cost Threshold
REA	New Mexico’s Renewable Energy Act of 2004
REC	Renewable Energy Certificates
Red Mesa Wind	Red Mesa Wind Energy Center
REP	Retail Electricity Provider
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
S&P	Standard and Poor’s Ratings Services
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
Tax Act	Federal tax reform legislation enacted on December 22, 2017, commonly referred to as the Tax Cuts and Jobs Act
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 2018 Term Loan	TNMP’s $35.0 Million Unsecured Term Loan
TNMP 2019 Bonds	TNMP’s First Mortgage Bonds issuable under the TNMP 2019 Bond Purchase Agreement

6

TNMP 2019 Bond Purchase Agreement	TNMP’s Agreement to Issue an Aggregate of $305.0 Million in First Mortgage Bonds in 2019
TNMP Revolving Credit Facility	TNMP’s $75.0 Million Secured Revolving Credit Facility
Tri-State	Tri-State Generation and Transmission Association, Inc.
Tucson	Tucson Electric Power Company
UAMPS	Utah Associated Municipal Power Systems
US Supreme Court	United States Supreme Court
Valencia	Valencia Energy Facility
VIE	Variable Interest Entity
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, formerly an indirect wholly-owned subsidiary of Westmoreland
WSJ LLC	Westmoreland San Juan Mining, LLC, a subsidiary of Westmoreland Mining Holdings, LLC, and successor entity to SJCC

7

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands, except per share amounts)
Electric Operating Revenues:
Contracts with customers	$	315,698		$	303,351
Alternative revenue programs	636			924
Other electric operating revenue	33,311			13,603
Total electric operating revenues	349,645			317,878
Operating Expenses:
Cost of energy	121,626			92,556
Administrative and general	52,336			48,283
Energy production costs	35,072			35,350
Regulatory disallowances and restructuring costs	1,345			—
Depreciation and amortization	65,356			58,722
Transmission and distribution costs	16,678			16,955
Taxes other than income taxes	20,509			19,880
Total operating expenses	312,922			271,746
Operating income	36,723			46,132
Other Income and Deductions:
Interest income	3,619			4,124
Gains on investment securities	14,014			288
Other income	3,415			3,469
Other (deductions)	(3,252		)	(1,376		)
Net other income and deductions	17,796			6,505
Interest Charges	31,634			33,055
Earnings before Income Taxes	22,885			19,582
Income Taxes	1,223			783
Net Earnings	21,662			18,799
(Earnings) Attributable to Valencia Non-controlling Interest	(2,830		)	(3,677		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)
Net Earnings Attributable to PNMR	$	18,700		$	14,990
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.23		$	0.19
Diluted	$	0.23		$	0.19
Dividends Declared per Common Share	$	0.290		$	0.265

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

8

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Net Earnings	$	21,662		$	18,799
Other Comprehensive Income:
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(1,798) and $(283)	5,280			832
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $172 and $668	(504		)	(1,961		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(470) and $(480)	1,381			1,411
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $311 and $(472)	(914		)	1,386
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(68) and $13	202			(40		)
Total Other Comprehensive Income	5,445			1,628
Comprehensive Income	27,107			20,427
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(2,830		)	(3,677		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)
Comprehensive Income Attributable to PNMR	$	24,145		$	16,618

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

9

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	21,662		$	18,799
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	73,946			67,748
Deferred income tax expense	1,122			767
(Gains) on investment securities	(14,014		)	(288		)
Stock based compensation expense	3,257			2,894
Regulatory disallowances and restructuring costs	1,345			—
Allowance for equity funds used during construction	(2,049		)	(2,487		)
Other, net	444			729
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	15,842			18,215
Materials, supplies, and fuel stock	3,826			(2,976		)
Other current assets	(1,778		)	2,345
Other assets	13,463			(443		)
Accounts payable	(7,642		)	(26,953		)
Accrued interest and taxes	6,443			13,370
Other current liabilities	2,060			(9,397		)
Other liabilities	(13,243		)	(3,397		)
Net cash flows from operating activities	104,684			78,926
Cash Flows From Investing Activities:
Additions to utility plant	(141,986		)	(117,691		)
Proceeds from sales of investment securities	74,460			626,729
Purchases of investment securities	(77,363		)	(628,999		)
Principal repayments on Westmoreland Loan	—			5,649
Investments in NMRD	(7,000		)	(5,000		)
Other, net	(13		)	128
Net cash flows from investing activities	(151,902		)	(119,184		)

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

10

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	(12,100		)	(66,700		)
Long-term borrowings	475,000			299,652
Repayment of long-term debt	(200,000		)	(155,026		)
Proceeds from stock option exercise	930			802
Awards of common stock	(8,936		)	(10,845		)
Dividends paid	(23,232		)	(21,240		)
Valencia’s transactions with its owner	(4,263		)	(4,472		)
Debt issuance costs and other, net	(2,215		)	(2,104		)
Net cash flows from financing activities	225,184			40,067
Change in Cash, Restricted Cash, and Equivalents	177,966			(191		)
Cash, Restricted Cash, and Equivalents at Beginning of Period	2,122			3,974
Cash, Restricted Cash, and Equivalents at End of Period	$	180,088		$	3,783
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	20,518		$	15,305
Income taxes paid (refunded), net	$	(235	)	$	(8	)
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	26,636		$	16,003

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

11

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2019		December 31, 2018
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	180,088	$	2,122
Accounts receivable, net of allowance for uncollectible accounts of $1,151 and $1,406	94,624		92,800
Unbilled revenues	39,011		57,092
Other receivables	13,849		11,369
Materials, supplies, and fuel stock	68,008		71,834
Regulatory assets	—		4,534
Income taxes receivable	7,630		7,965
Other current assets	53,863		54,808
Total current assets	457,073		302,524
Other Property and Investments:
Investment securities	351,563		328,242
Equity investment in NMRD	33,528		26,564
Other investments	299		297
Non-utility property, net	6,229		3,404
Total other property and investments	391,619		358,507
Utility Plant:
Plant in service and held for future use	7,610,093		7,548,581
Less accumulated depreciation and amortization	2,641,320		2,604,177
	4,968,773		4,944,404
Construction work in progress	225,485		194,427
Nuclear fuel, net of accumulated amortization of $48,675 and $42,511	95,713		95,798
Net utility plant	5,289,971		5,234,629
Deferred Charges and Other Assets:
Regulatory assets	588,266		598,930
Goodwill	278,297		278,297
Operating lease right-of-use assets, net of accumulated amortization	150,426		—
Other deferred charges	95,106		92,664
Total deferred charges and other assets	1,112,095		969,891
	$	7,250,758	$	6,865,551

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

12

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2019			December 31, 2018
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	223,800		$	235,900
Current installments of long-term debt	172,302			—
Accounts payable	77,893			112,170
Customer deposits	10,749			10,695
Accrued interest and taxes	71,264			65,156
Regulatory liabilities	19,245			9,446
Operating lease liabilities	26,197			—
Dividends declared	23,231			23,231
Other current liabilities	39,452			55,855
Total current liabilities	664,133			512,453
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	2,771,939			2,670,111
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	613,989			600,719
Regulatory liabilities	889,342			891,428
Asset retirement obligations	161,685			158,674
Accrued pension liability and postretirement benefit cost	96,374			100,375
Operating lease liabilities	124,937			—
Other deferred credits	169,372			167,668
Total deferred credits and other liabilities	2,055,699			1,918,864
Total liabilities	5,491,771			5,101,428
Commitments and Contingencies (Note 11)
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)	1,148,364			1,153,113
Accumulated other comprehensive income (loss), net of income taxes	(103,239		)	(108,684		)
Retained earnings	639,554			643,953
Total PNMR common stockholders’ equity	1,684,679			1,688,382
Non-controlling interest in Valencia	62,779			64,212
Total equity	1,747,458			1,752,594
	$	7,250,758		$	6,865,551

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

13

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

	Attributable to PNMR												Non- controlling Interest in Valencia
	Common Stock			AOCI			Retained Earnings			Total PNMR Common Stockholders’ Equity						Total Equity
	(In thousands)
Balance at December 31, 2018	$	1,153,113		$	(108,684	)	$	643,953		$	1,688,382		$	64,212		$	1,752,594
Net earnings before subsidiary preferred stock dividends	—			—			18,832			18,832			2,830			21,662
Total other comprehensive income	—			5,445			—			5,445			—			5,445
Subsidiary preferred stock dividends	—			—			(132		)	(132		)	—			(132		)
Dividends declared on common stock	—			—			(23,099		)	(23,099		)	—			(23,099		)
Proceeds from stock option exercise	930			—			—			930			—			930
Awards of common stock	(8,936		)	—			—			(8,936		)	—			(8,936		)
Stock based compensation expense	3,257			—			—			3,257			—			3,257
Valencia’s transactions with its owner	—			—			—			—			(4,263		)	(4,263		)
Balance at March 31, 2019	$	1,148,364		$	(103,239	)	$	639,554		$	1,684,679		$	62,779		$	1,747,458

Balance at December 31, 2017, as originally reported	$	1,157,665		$	(95,940	)	$	633,528		$	1,695,253		$	66,195		$	1,761,448
Cumulative effect adjustment (Note 7)	—			(11,208		)	11,208			—			—			—
Balance at January 1, 2018, as adjusted	1,157,665			(107,148		)	644,736			1,695,253			66,195			1,761,448
Net earnings before subsidiary preferred stock dividends	—			—			15,122			15,122			3,677			18,799
Total other comprehensive income	—			1,628			—			1,628			—			1,628
Subsidiary preferred stock dividends	—			—			(132		)	(132		)	—			(132		)
Dividends declared on common stock	—			—			(21,108		)	(21,108		)	—			(21,108		)
Proceeds from stock option exercise	802			—			—			802			—			802
Awards of common stock	(10,845		)	—			—			(10,845		)	—			(10,845		)
Stock based compensation expense	2,894			—			—			2,894			—			2,894
Valencia’s transactions with its owner	—			—			—			—			(4,472		)	(4,472		)
Balance at March 31, 2018	$	1,150,516		$	(105,520	)	$	638,618		$	1,683,614		$	65,400		$	1,749,014

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

14

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Electric Operating Revenues:
Contracts with customers	$	235,941		$	222,564
Alternative revenue programs	66			65
Other electric operating revenue	33,311			13,603
Total electric operating revenues	269,318			236,232
Operating Expenses:
Cost of energy	99,339			70,802
Administrative and general	47,402			43,726
Energy production costs	35,072			35,350
Regulatory disallowances and restructuring costs	1,345			—
Depreciation and amortization	39,224			36,627
Transmission and distribution costs	10,633			9,827
Taxes other than income taxes	12,010			11,608
Total operating expenses	245,025			207,940
Operating income	24,293			28,292
Other Income and Deductions:
Interest income	3,656			2,487
Gains on investment securities	14,014			288
Other income	2,632			2,391
Other (deductions)	(2,288		)	(1,462		)
Net other income and deductions	18,014			3,704
Interest Charges	18,360			20,830
Earnings before Income Taxes	23,947			11,166
Income Taxes	1,973			(348		)
Net Earnings	21,974			11,514
(Earnings) Attributable to Valencia Non-controlling Interest	(2,830		)	(3,677		)
Net Earnings Attributable to PNM	19,144			7,837
Preferred Stock Dividends Requirements	(132		)	(132		)
Net Earnings Available for PNM Common Stock	$	19,012		$	7,705

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

15

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Net Earnings	$	21,974		$	11,514
Other Comprehensive Income:
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(1,798) and $(283)	5,280			832
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $172 and $668	(504		)	(1,961		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(470) and $(480)	1,381			1,411
Total Other Comprehensive Income	6,157			282
Comprehensive Income	28,131			11,796
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(2,830		)	(3,677		)
Comprehensive Income Attributable to PNM	$	25,301		$	8,119

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

16

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	21,974		$	11,514
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	47,218			45,165
Deferred income tax expense	2,063			(253		)
(Gains) on investment securities	(14,014		)	(288		)
Regulatory disallowances and restructuring costs	1,345			—
Allowance for equity funds used during construction	(1,807		)	(2,031		)
Other, net	432			729
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	15,212			15,100
Materials, supplies, and fuel stock	3,671			(2,247		)
Other current assets	(4,098		)	(248		)
Other assets	10,399			3,999
Accounts payable	(8,257		)	(18,014		)
Accrued interest and taxes	14,764			17,984
Other current liabilities	32,683			(13,868		)
Other liabilities	(13,524		)	(4,381		)
Net cash flows from operating activities	108,061			53,161
Cash Flows From Investing Activities:
Additions to utility plant	(75,876		)	(61,720		)
Proceeds from sales of investment securities	74,460			626,729
Purchases of investment securities	(77,363		)	(628,999		)
Other, net	(48		)	128
Net cash flows from investing activities	(78,827		)	(63,862		)

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

17

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	(42,400		)	(39,800		)
Short-term borrowings (repayments) – affiliate, net	(19,800		)	54,600
Long-term borrowings	250,000			—
Repayment of long-term debt	(200,000		)	—
Dividends paid	(132		)	(132		)
Valencia’s transactions with its owner	(4,263		)	(4,472		)
Debt issuance costs and other, net	(635		)	(584		)
Net cash flows from financing activities	(17,230		)	9,612
Change in Cash, Restricted Cash, and Equivalents	12,004			(1,089		)
Cash, Restricted Cash, and Equivalents at Beginning of Period	85			1,108
Cash, Restricted Cash, and Equivalents at End of Period	$	12,089		$	19
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	9,070		$	9,560
Income taxes paid (refunded), net	$	—		$	—
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	11,407		$	2,682

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

18

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2019		December 31, 2018
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	12,089	$	85
Accounts receivable, net of allowance for uncollectible accounts of $1,151 and $1,406	68,724		68,603
Unbilled revenues	31,366		47,113
Other receivables	14,370		10,650
Affiliate receivables	8,854		15,871
Materials, supplies, and fuel stock	63,426		67,097
Regulatory assets	—		4,534
Income taxes receivable	12,940		12,850
Other current assets	43,650		43,516
Total current assets	255,419		270,319
Other Property and Investments:
Investment securities	351,563		328,242
Other investments	93		91
Non-utility property, net	1,693		96
Total other property and investments	353,349		328,429
Utility Plant:
Plant in service and held for future use	5,664,174		5,623,520
Less accumulated depreciation and amortization	2,033,511		2,006,266
	3,630,663		3,617,254
Construction work in progress	143,673		134,221
Nuclear fuel, net of accumulated amortization of $48,675 and $42,511	95,713		95,798
Net utility plant	3,870,049		3,847,273
Deferred Charges and Other Assets:
Regulatory assets	454,987		460,903
Goodwill	51,632		51,632
Operating lease right-of-use assets, net of accumulated amortization	137,756		—
Other deferred charges	78,847		77,327
Total deferred charges and other assets	723,222		589,862
	$	5,202,039	$	5,035,883

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

19

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2019			December 31, 2018
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	—		$	42,400
Short-term debt - affiliate	—			19,800
Accounts payable	55,449			75,114
Affiliate payables	12,627			164
Customer deposits	10,749			10,695
Accrued interest and taxes	50,621			35,767
Regulatory liabilities	16,895			5,975
Operating lease liabilities	22,762			—
Dividends declared	132			132
Other current liabilities	26,432			32,976
Total current liabilities	195,667			223,023
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,706,873			1,656,490
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	513,783			502,767
Regulatory liabilities	708,295			713,971
Asset retirement obligations	160,807			157,814
Accrued pension liability and postretirement benefit cost	89,338			92,981
Operating lease liabilities	115,436			—
Other deferred credits	215,004			215,737
Total deferred credits and liabilities	1,802,663			1,683,270
Total liabilities	3,705,203			3,562,783
Commitments and Contingencies (Note 11)
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	(104,265		)	(110,422		)
Retained earnings	261,875			242,863
Total PNM common stockholder’s equity	1,422,528			1,397,359
Non-controlling interest in Valencia	62,779			64,212
Total equity	1,485,307			1,461,571
	$	5,202,039		$	5,035,883

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

20

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

	Attributable to PNM
									Total PNM Common Stockholder’s Equity			Non- controlling  Interest in Valencia
	Common Stock		AOCI			Retained Earnings									Total Equity
	(In thousands)
Balance at December 31, 2018	$	1,264,918	$	(110,422	)	$	242,863		$	1,397,359		$	64,212		$	1,461,571
Net earnings	—		—			19,144			19,144			2,830			21,974
Total other comprehensive income	—		6,157			—			6,157			—			6,157
Dividends declared on preferred stock	—		—			(132		)	(132		)	—			(132		)
Valencia’s transactions with its owner	—		—			—			—			(4,263		)	(4,263		)
Balance at March 31, 2019	$	1,264,918	$	(104,265	)	$	261,875		$	1,422,528		$	62,779		$	1,485,307

Balance at December 31, 2017, as originally reported	$	1,264,918	$	(97,093	)	$	254,349		$	1,422,174		$	66,195		$	1,488,369
Cumulative effect adjustment (Note 7)	—		(11,208		)	11,208			—			—			—
Balance at January 1, 2018, as adjusted	1,264,918		(108,301		)	265,557			1,422,174			66,195			1,488,369
Net earnings	—		—			7,837			7,837			3,677			11,514
Total other comprehensive income	—		282			—			282			—			282
Dividends declared on preferred stock	—		—			(132		)	(132		)	—			(132		)
Valencia’s transactions with its owner	—		—			—			—			(4,472		)	(4,472		)
Balance at March 31, 2018	$	1,264,918	$	(108,019	)	$	273,262		$	1,430,161		$	65,400		$	1,495,561

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

21

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Electric Operating Revenues:
Contracts with customers	$	79,757		$	80,787
Alternative revenue programs	570			859
Total Electric Operating Revenues	80,327			81,646
Operating Expenses:
Cost of energy	22,287			21,754
Administrative and general	11,558			10,709
Depreciation and amortization	20,214			16,387
Transmission and distribution costs	6,045			7,128
Taxes other than income taxes	7,638			7,136
Total operating expenses	67,742			63,114
Operating income	12,585			18,532
Other Income and Deductions:
Interest income	31			—
Other income	717			754
Other (deductions)	(163		)	331
Net other income and deductions	585			1,085
Interest Charges	8,800			7,729
Earnings before Income Taxes	4,370			11,888
Income Taxes	272			2,475
Net Earnings	$	4,098		$	9,413

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

22

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	4,098		$	9,413
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	20,514			16,836
Deferred income tax expense (benefit)	(4,343		)	(953		)
Allowance for equity funds used during construction and other, net	(231		)	(456		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	630			3,115
Materials and supplies	155			(729		)
Other current assets	581			331
Other assets	2,712			(3,055		)
Accounts payable	1,075			(4,400		)
Accrued interest and taxes	(990		)	(1,952		)
Other current liabilities	3,190			5,874
Other liabilities	(1,536		)	1,456
Net cash flows from operating activities	25,855			25,480
Cash Flows From Investing Activities:
Additions to utility plant	(58,624		)	(49,956		)
Net cash flows from investing activities	(58,624		)	(49,956		)
Cash Flow From Financing Activities:
Revolving credit facilities borrowings (repayments), net	(17,500		)	21,200
Short-term borrowings (repayments) – affiliate, net	(100		)	2,600
Long-term borrowings	225,000			—
Dividends paid	(10,713		)	(1,024		)
Debt issuance costs and other, net	(1,561		)	—
Net cash flows from financing activities	195,126			22,776
Change in Cash and Cash Equivalents	162,357			(1,700		)
Cash and Cash Equivalents at Beginning of Period	—			1700
Cash and Cash Equivalents at End of Period	$	162,357		$	—
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	3,829		$	1,830
Income taxes paid (refunded), net	$	(235	)	$	(8	)
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	10,646		$	9,868

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

23

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2019		December 31, 2018
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	162,357	$	—
Accounts receivable	25,900		24,196
Unbilled revenues	7,645		9,979
Other receivables	881		1,721
Affiliate receivables	—		164
Materials and supplies	4,582		4,737
Other current assets	1,373		1,114
Total current assets	202,738		41,911
Other Property and Investments:
Other investments	206		206
Non-utility property, net	3,468		2,240
Total other property and investments	3,674		2,446
Utility Plant:
Plant in service and plant held for future use	1,702,427		1,686,119
Less accumulated depreciation and amortization	491,776		487,734
	1,210,651		1,198,385
Construction work in progress	75,332		51,459
Net utility plant	1,285,983		1,249,844
Deferred Charges and Other Assets:
Regulatory assets	133,279		138,027
Goodwill	226,665		226,665
Operating lease right-of-use assets, net of accumulated amortization	12,160		—
Other deferred charges	7,281		6,284
Total deferred charges and other assets	379,385		370,976
	$	1,871,780	$	1,665,177

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

24

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2019		December 31, 2018
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	—	$	17,500
Short-term debt – affiliate	—		100
Current installments of long-term debt	172,302		—
Accounts payable	14,234		23,804
Affiliate payables	4,771		1,210
Accrued interest and taxes	40,892		41,882
Regulatory liabilities	2,350		3,471
Operating lease liabilities	3,023		—
Other current liabilities	3,556		2,861
Total current liabilities	241,128		90,828
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	626,639		575,398
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	134,757		136,238
Regulatory liabilities	181,047		177,458
Asset retirement obligations	878		860
Accrued pension liability and postretirement benefit cost	7,036		7,394
Operating lease liabilities	9,088		—
Other deferred credits	3,729		2,908
Total deferred credits and other liabilities	336,535		324,858
Total liabilities	1,204,302		991,084
Commitments and Contingencies (Note 11)
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	534,166		534,166
Retained earnings	133,248		139,863
Total common stockholder’s equity	667,478		674,093
	$	1,871,780	$	1,665,177

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

25

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCKHOLDER’S EQUITY

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Total Common Stockholder’s Equity
	(In thousands)
Balance at December 31, 2018	$	64	$	534,166	$	139,863		$	674,093
Net earnings	—		—		4,098			4,098
Dividends declared on common stock	—		—		(10,713		)	(10,713		)
Balance at March 31, 2019	$	64	$	534,166	$	133,248		$	667,478

Balance at December 31, 2017	$	64	$	504,166	$	130,175		$	634,405
Net earnings	—		—		9,413			9,413
Dividends declared on common stock	—		—		(1,024		)	(1,024		)
Balance at March 31, 2018	$	64	$	504,166	$	138,564		$	642,794

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

26

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Significant Accounting Policies and Responsibility for Financial Statements

Financial Statement Preparation

In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at March 31, 2019 and December 31, 2018, and the consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2019 and 2018. 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. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.

The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. 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 2018 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2019 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual audited Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s, and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2018 Annual Reports on Form 10-K.

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 Condensed 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 6). 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’ expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, equity transactions, and interconnection billings (Note 15). All intercompany transactions and balances have been eliminated.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by the Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board.

TNMP declared and paid cash dividends on common stock to PNMR of $10.7 million and $1.0 million in the three months ended March 31, 2019 and 2018.

27

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Investment in NM Renewable Development, LLC

As discussed in Note 1 of the 2018 Annual Reports on Form 10-K, PNMR Development and AEP OnSite Partners created NMRD in September 2017 to pursue the acquisition, development, and ownership of renewable energy generation projects, primarily in the state of New Mexico. NMRD’s current renewable energy capacity in operation is 33.9 MW. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. The investment in NMRD is accounted for using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over NMRD and its operations.

In the three months ended March 31, 2019 and 2018, PNMR Development made cash contributions of $7.0 million and $5.0 million to NMRD to be used primarily for its construction activities. For the three months ended March 31, 2019 and 2018, NMRD had revenues of $0.7 million and $0.4 million and net earnings (losses) of $(0.1) million and $0.1 million. At March 31, 2019 and December 31, 2018, NMRD had $8.0 million and $2.6 million of current assets, $65.2 million and $50.8 million of property, plant, and equipment and other assets, $6.1 million and $0.2 million of current liabilities, and $67.1 million and $53.2 million of owners’ equity.

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.

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 certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. In November 2018, the FASB clarified that receivables arising from operating leases are not within the scope of Topic 326 for assets measured at amortized costs. Instead, impairments of receivables arising from operating leases should be accounted for in accordance with Topic 842. The Company anticipates adopting ASU 2016-13 as of January 1, 2020, its required effective date. The Company is in the process of analyzing the impacts of this new standard, but does not anticipate it will have a significant impact on its financial statements.

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, 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.

28

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Accounting Standards Update 2018-13 – Fair Value Measurements (Topic 820) Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurements

In August 2018, the FASB issued ASU 2018-13 to improve fair value disclosures. ASU 2018-13 eliminates certain disclosure requirements related to transfers between Levels 1 and 2 of the fair value hierarchy and the requirement to disclose the valuation process for Level 3 fair value measurements. ASU 2018-13 also amends certain disclosure requirements for investments measured at net asset value and requires new disclosures for Level 3 investments, including a new requirement to disclose changes in unrealized gains or losses recorded in OCI related to Level 3 fair value measurements. ASU 2018-13 is effective for the Company beginning on January 1, 2020, and permits entities to adopt all or certain elements of the new guidance prior to its effective date. ASU 2018-13 requires retrospective application, except for the new disclosures related to Level 3 investments which are to be applied prospectively. As discussed in Note 9 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 7, PNM and TNMP have investment securities in trusts for decommissioning, reclamation, pension benefits, and other postretirement benefits, which are measured at fair value. Certain investments in these trusts are measured at net asset value per share. These trusts also hold Level 3 investments. The Company is evaluating the requirements of ASU 2018-13, but does not anticipate it will have a significant impact on the Company’s fair value disclosures.

Accounting Standards Update 2018-14 – Compensation - Retirement Benefits - Defined Benefit Plans (Topic 715) Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans

In August 2018, the FASB issued ASU 2018-14 to improve benefit plan sponsors’ disclosures for defined benefit pension and other post-employment benefit plans. ASU 2018-14 removes the requirement to disclose the amounts in other comprehensive income expected to be recognized as benefit cost over the next fiscal year and the requirement to disclose the impact of a one-percentage-point change in the assumed health care cost trend rate; clarifies the disclosure requirements for plans with assets that are less than their projected benefit, or accumulated benefit obligation; and requires significant gains and losses affecting benefit obligations during the period be disclosed. ASU 2018-14 is effective for the Company on December 31, 2020, although early adoption is permitted, and requires retrospective application. As discussed in Note 11 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 10, PNM and TNMP maintain qualified defined benefit, other postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The Company is evaluating the requirements of ASU 2018-14 but does not anticipate these changes will have a significant impact on the Company’s defined benefit and other postretirement benefit plan disclosures.

Accounting Standards Update 2018-15 – Intangibles - Goodwill and Other - Internal Use Software (Topic 350): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract

In August 2018, the FASB issued ASU 2018-15 to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for implementation costs incurred to develop or obtain internal-use software. Under ASU 2018-15, entities are required to capitalize implementation costs for hosting arrangements if those costs meet the capitalization requirements for internal-use software arrangements. ASU 2018-15 requires entities to present cash flows, capitalized costs, and amortization expense in the same financial statement line items as other costs incurred for such hosting arrangements. ASU 2018-15 is effective for the Company on January 1, 2020, although early adoption is permitted, and allows entities to apply the new requirements retrospectively or prospectively. The Company is in the process of analyzing the impacts of this new standard.

Accounting Standards Update 2018-18 - Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606

In November 2018, the FASB issued ASU 2018-18 to clarify transactions between collaborative arrangement participants that should be recognized as revenue under Topic 606. ASU 2018-18 is effective for the Company on January 1, 2020, although early adoption is permitted, and requires retrospective application. The Company has collaborative arrangements related to its interests in SJGS, Four Corners, PVNGS, and Luna. The Company believes its current accounting practices comply with the requirements of ASU 2018-18 but is in the process of analyzing the impacts of the new standard.

(2) Segment Information

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

29

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 capacity, as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale power and transmission rates.

TNMP

TNMP is an electric utility providing services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. TNMP also provides transmission services at regulated rates to other utilities that interconnect with TNMP’s facilities.

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, NM Capital, and the equity method investment in NMRD are also included in Corporate and Other. Eliminations of intercompany income and expense transactions are reflected in the Corporate and Other segment.

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

PNMR SEGMENT INFORMATION

	PNM			TNMP			Corporate and Other			PNMR Consolidated
	(In thousands)
Three Months Ended March 31, 2019
Electric operating revenues	$	269,318		$	80,327		$	—		$	349,645
Cost of energy	99,339			22,287			—			121,626
Utility margin	169,979			58,040			—			228,019
Other operating expenses	106,462			25,241			(5,763		)	125,940
Depreciation and amortization	39,224			20,214			5,918			65,356
Operating income (loss)	24,293			12,585			(155		)	36,723
Interest income	3,656			31			(68		)	3,619
Other income (deductions)	14,358			554			(735		)	14,177
Interest charges	(18,360		)	(8,800		)	(4,474		)	(31,634		)
Segment earnings (loss) before income taxes	23,947			4,370			(5,432		)	22,885
Income taxes (benefit)	1,973			272			(1,022		)	1,223
Segment earnings (loss)	21,974			4,098			(4,410		)	21,662
Valencia non-controlling interest	(2,830		)	—			—			(2,830		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	19,012		$	4,098		$	(4,410	)	$	18,700
At March 31, 2019:
Total Assets	$	5,202,039		$	1,871,780		$	176,939		$	7,250,758
Goodwill	$	51,632		$	226,665		$	—		$	278,297

30

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	PNM			TNMP			Corporate and Other			PNMR Consolidated
	(In thousands)
Three Months Ended March 31, 2018
Electric operating revenues	$	236,232		$	81,646		$	—		$	317,878
Cost of energy	70,802			21,754			—			92,556
Utility margin	165,430			59,892			—			225,322
Other operating expenses	100,511			24,973			(5,016		)	120,468
Depreciation and amortization	36,627			16,387			5,708			58,722
Operating income (loss)	28,292			18,532			(692		)	46,132
Interest income	2,487			—			1,637			4,124
Other income (deductions)	1,217			1,085			79			2,381
Interest charges	(20,830		)	(7,729		)	(4,496		)	(33,055		)
Segment earnings (loss) before income taxes	11,166			11,888			(3,472		)	19,582
Income taxes (benefit)	(348		)	2,475			(1,344		)	783
Segment earnings (loss)	11,514			9,413			(2,128		)	18,799
Valencia non-controlling interest	(3,677		)	—			—			(3,677		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	7,705		$	9,413		$	(2,128	)	$	14,990
At March 31, 2018:
Total Assets	$	4,925,741		$	1,526,434		$	224,218		$	6,676,393
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.

31

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(3) Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2019 and 2018 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	PNM									PNMR
	Unrealized									Fair Value
	Gains on									Adjustment
	Available-for-			Pension						for Cash
	Sale			Liability						Flow
	Securities			Adjustment			Total			Hedges			Total
	(In thousands)
Balance at December 31, 2018	$	1,939		$	(112,361	)	$	(110,422	)	$	1,738		$	(108,684	)
Amounts reclassified from AOCI (pre-tax)	(676		)	1,851			1,175			270			1,445
Income tax impact of amounts reclassified	172			(470		)	(298		)	(68		)	(366		)
Other OCI changes (pre-tax)	7,078			—			7,078			(1,225		)	5,853
Income tax impact of other OCI changes	(1,798		)	—			(1,798		)	311			(1,487		)
Net after-tax change	4,776			1,381			6,157			(712		)	5,445
Balance at March 31, 2019	$	6,715		$	(110,980	)	$	(104,265	)	$	1,026		$	(103,239	)

Balance at December 31, 2017, as originally reported	$	13,169		$	(110,262	)	$	(97,093	)	$	1,153		$	(95,940	)
Cumulative effect adjustment (Note 7)	(11,208		)	—			(11,208		)	—			(11,208		)
Balance at January 1, 2018, as adjusted	1,961			(110,262		)	(108,301		)	1,153			(107,148		)
Amounts reclassified from AOCI (pre-tax)	(2,629		)	1,891			(738		)	(53		)	(791		)
Income tax impact of amounts reclassified	668			(480		)	188			13			201
Other OCI changes (pre-tax)	1,115			—			1,115			1,858			2,973
Income tax impact of other OCI changes	(283		)	—			(283		)	(472		)	(755		)
Net after-tax change	(1,129		)	1,411			282			1,346			1,628
Balance at March 31, 2018	$	832		$	(108,851	)	$	(108,019	)	$	2,499		$	(105,520	)

The Condensed Consolidated Statements of Earnings include pre-tax amounts reclassified from AOCI related to Unrealized Gains on Available-for-Sale Securities in gains on investment securities, related to Pension Liability Adjustment in other (deductions), and related to Fair Value Adjustment for Cash Flow Hedges in interest charges. The income tax impacts of all amounts reclassified from AOCI are included in income taxes in the Condensed Consolidated Statements of Earnings.

32

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(4) Earnings Per Share

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

	Three Months Ended
	March 31,
	2019		2018
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	18,700	$	14,990
Average Number of Common Shares:
Outstanding during period	79,654		79,654
Vested awards of restricted stock	239		205
Average Shares – Basic	79,893		79,859
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	78		154
Average Shares – Diluted	79,971		80,013
Net Earnings Per Share of Common Stock:
Basic	$	0.23	$	0.19
Diluted	$	0.23	$	0.19

(5) Electric Operating Revenues

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.

Additional information concerning electric operating revenue is contained in Note 4 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Disaggregation of Revenues

A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects alternative revenue program revenues (“ARP”) and other revenues.

	PNM		TNMP		PNMR Consolidated
Three Months Ended March 31, 2019	(In thousands)
Electric Operating Revenues:
Contracts with customers:
Retail electric revenue
Residential	$	107,302	$	30,432	$	137,734
Commercial	85,233		27,429		112,662
Industrial	14,747		5,616		20,363
Public authority	4,711		1,374		6,085
Economy energy service	6,922		—		6,922
Transmission	13,385		14,003		27,388
Miscellaneous	3,641		903		4,544
Total revenues from contracts with customers	235,941		79,757		315,698
Alternative revenue programs	66		570		636
Other electric operating revenues	33,311		—		33,311
Total Electric Operating Revenues	$	269,318	$	80,327	$	349,645

33

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	PNM		TNMP		PNMR Consolidated
Three Months Ended March 31, 2018	(In thousands)
Electric Operating Revenues:
Contracts with customers:
Retail electric revenue
Residential	$	97,169	$	29,266	$	126,435
Commercial	82,849		27,152		110,001
Industrial	13,459		4,305		17,764
Public authority	4,635		1,416		6,051
Economy energy service	7,288		—		7,288
Transmission	12,482		16,508		28,990
Miscellaneous	4,682		2,140		6,822
Total revenues from contracts with customers	222,564		80,787		303,351
Alternative revenue programs	65		859		924
Other electric operating revenues	13,603		—		13,603
Total Electric Operating Revenues	$	236,232	$	81,646	$	317,878

Contract balances

Performance obligations related to contracts with customers are typically satisfied when the energy is delivered and the customer or end-user utilizes the energy. Accounts receivable from customers represent amounts billed to the customer or end-user, including amounts under ARP programs. For PNM, accounts receivable reflected on the Condensed Consolidated Balance Sheets, net of allowance for uncollectible accounts, includes $65.2 million at March 31, 2019 and $61.7 million at December 31, 2018 resulting from contracts with customers. All of TNMP’s accounts receivable results from contracts with customers.

Contract assets are an entity’s right to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditioned on something other than the passage of time (for example, the entity’s future performance). The Company has no contract assets as of March 31, 2019 or December 31, 2018. Contract liabilities arise when consideration is received in advance from a customer before satisfying the performance obligations. Therefore, revenue is deferred and not recognized until the obligation is satisfied. Under its Open Access Transmission Tariff, PNM accepts upfront consideration for capacity reservations requested by transmission customers, which requires PNM to defer the customer’s transmission capacity rights for a specific period of time. PNM recognizes the revenue of these capacity reservations over the period the capacity rights have been reserved, which is generally over one year. Other utilities pay PNM and TNMP in advance for the joint-use of their utility poles. These revenues are recognized over the period of time specified in the joint-use contract, typically for one calendar year. Deferred revenues on these arrangements are recorded as contract liabilities. The Company has no other arrangements with remaining performance obligations to which a portion of the transaction price would be required to be allocated.

Changes during the period in the balances of contract liabilities, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, are as follows:

	PNM			TNMP			PNMR Consolidated
	(In thousands)
Balance at December 31, 2018	$	349		$	—		$	349
Consideration received in advance of service to be provided	3,981			1,389			5,370
Deferred revenue earned	(1,349		)	(371		)	(1,720		)
Balance at March 31, 2019	$	2,981		$	1,018		$	3,999

34

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(6) 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. Additional information concerning PNM’s VIEs is contained in Note 10 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

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 three months ended March 31, 2019 and 2018, PNM paid $4.9 million and $4.9 million for fixed charges and less than $0.1 million and $0.3 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 Condensed 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 Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

	Results of Operations
	Three Months Ended March 31,
	2019			2018
	(In thousands)
Operating revenues	$	4,952		$	4,768
Operating expenses	(2,122		)	(1,091		)
Earnings attributable to non-controlling interest	$	2,830		$	3,677

	Financial Position
	March 31,		December 31,
	2019		2018
	(In thousands)
Current assets	$	2,918	$	2,684
Net property, plant, and equipment	60,712		62,066
Total assets	63,630		64,750
Current liabilities	851		538
Owners’ equity – non-controlling interest	$	62,779	$	64,212

35

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Westmoreland San Juan Mining, LLC

As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS under a coal supply agreement (“SJGS CSA”). That section includes information on the acquisition of SJCC by WSJ, a subsidiary of Westmoreland Coal Company (“Westmoreland”), on January 31, 2016, as well as the $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 purchase of SJCC. On May 22, 2018, the full principal outstanding under the Westmoreland Loan of $50.1 million was repaid. NM Capital used a portion of the proceeds to repay all remaining amounts owed under the BTMU Term Loan. These payments effectively terminated the loan agreements and PNMR’s guarantee of NM Capital’s obligations under the BTMU Term Loan. Prior to its repayment, the Westmoreland Loan resulted in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital were subject to possible loss in the event of default of WSJ.

On October 9, 2018, Westmoreland filed a Current Report on Form 8-K with the SEC announcing it had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. On March 15, 2019, Westmoreland emerged from Chapter 11 bankruptcy as a privately held company owned and operated by a group of its former creditors. Under the reorganization, the assets of SJCC were sold to Westmoreland San Juan Mining, LLC (“WSJ LLC”), a subsidiary of Westmoreland Mining Holdings, LLC. The March 15, 2019 announcement indicated that mining operations will continue in the normal course of business. As successor entity to SJCC, WSJ LLC assumed all rights and obligations of WSJ including obligations to PNM under the SJGS CSA and to PNMR for the letters of credit support agreement. See (Note 11).

PNMR issued $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. As discussed above, WSJ LLC assumed the rights and obligations of SJCC, including obligations to PNMR for the letters of credit. The letters of credit support results in PNMR being considered to have a variable interest in WSJ LLC since PNMR is subject to possible loss in the event performance by PNMR is required under the letters of credit support. 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 WSJ LLC 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. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations.

WSJ LLC is considered to be a VIE.  PNMR’s analysis of its arrangements with WSJ LLC concluded that WSJ LLC has the ability to direct its mining operations, which is the factor that most significantly impacts the economic performance of WSJ LLC.  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 WSJ LLC, 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.  PNM’s involvement through the SJGS CSA, which was assumed by WSJ LLC pursuant to the March 15, 2019 purchase of the assets owned by SJCC by WSJ LLC, is a protective right rather than a participating right and WSJ LLC has the power to direct the activities that most significantly impact the economic performance of WSJ LLC.  The SJGS CSA requires WSJ LLC 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 WSJ LLC is able to mine more efficiently than anticipated, its economic performance will be improved.  Conversely, if WSJ LLC cannot mine as efficiently as anticipated, its economic performance will be negatively impacted.  Accordingly, PNMR believes WSJ LLC is the primary beneficiary and, therefore, WSJ LLC is not consolidated by either PNMR or PNM. The amounts outstanding under the letter of credit support constitute PNMR’s maximum exposure to loss from the VIE at March 31, 2019.

36

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(7) Fair Value of Derivative and Other Financial Instruments

Additional information concerning energy related derivative contracts and other financial instruments is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

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

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.

Beginning January 1, 2018, PNM is exposed to market risk for its 65 MW interest in SJGS Unit 4, which is held as merchant plant as ordered by the NMPRC. PNM has entered into agreements to sell 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 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. PNM passes the sales and purchases through to customers under PNM’s FPPAC.

PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. 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. PNM monitors the market risk of its commodity contracts 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 three months ended March 31, 2019 and the year ended December 31, 2018, PNM was not hedging its exposure to the variability in future cash flows

37

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

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
	March 31, 2019			December 31, 2018
	(In thousands)
Current assets	$	1,086		$	1,083
Deferred charges	2,265			2,511
	3,351			3,594
Current liabilities	(1,150		)	(1,177		)
Long-term liabilities	(2,265		)	(2,511		)
	(3,415		)	(3,688		)
Net	$	(64	)	$	(94	)

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 $3.3 million at March 31, 2019 and $3.6 million at December 31, 2018 resulting from PNM’s hazard sharing arrangements with Tri-State. The hazard sharing arrangements are net-settled upon delivery. Other amounts that could be offset under master netting agreements were immaterial.

At March 31, 2019 and December 31, 2018, PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at March 31, 2019 and December 31, 2018, amounts posted as cash collateral under margin arrangements were $1.0 million and $1.0 million. At March 31, 2019 and December 31, 2018, obligations to return cash collateral were $0.9 million and $1.0 million. Cash collateral amounts are included in other current assets and other current liabilities on the Condensed 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 insignificant amounts hedged under this plan as of March 31, 2019 and no amounts were hedged under this plan as of December 31, 2018.

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
	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
Electric operating revenues	$	28		$	(10	)
Cost of energy	(28		)	12
Total gain	$	—		$	2

38

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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
March 31, 2019	100,000	(400	)
December 31, 2018	100,000	—

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 March 31, 2019 and December 31, 2018, PNM had no such contracts in a net liability position.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Investment securities are carried at fair value. Investment 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 11). At March 31, 2019 and December 31, 2018, the fair value of investment securities included $308.0 million and $287.1 million for the NDT and $43.6 million and $41.1 million for the mine reclamation trusts.

As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, on January 1, 2018 the Company adopted Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10). Accordingly, on January 1, 2018 PNM recorded an after-tax cumulative effect adjustment of $11.2 million to reclassify unrealized holding gains on equity securities held in the NDT and coal mine reclamation trusts from AOCI to retained earnings on the Condensed Consolidated Balance Sheets. After January 1, 2018, all gains and losses resulting from sales and changes in the fair value of equity securities are recognized in earnings. Under ASU 2016-01, the accounting for available-for-sale debt securities remains essentially unchanged.

Gains and losses recognized on the Condensed Consolidated Statements of Earnings related to investment securities in the NDT and reclamation trusts are presented in the following table.

	Three Months Ended March 31,
	2019		2018
	(In thousands)
Equity securities:
Net gains from equity securities sold	$	1,387	$	2,828
Net gains from equity securities still held	9,602		136
Total net gains on equity securities	10,989		2,964
Available-for-sale debt securities:
Net gains (losses) on debt securities	3,025		(2,676		)
Net gains on investment securities	$	14,014	$	288

39

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The proceeds and gross realized gains and losses on the disposition of securities held in the NDT and coal mine reclamation trusts 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 $3.4 million and $(1.2) million for the three months ended March 31, 2019 and 2018.

	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
Proceeds from sales	$	74,460		$	626,729
Gross realized gains	$	4,189		$	6,021
Gross realized (losses)	$	(3,170	)	$	(4,677	)

The Company has no available-for-sale debt 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 March 31, 2019, the available-for-sale debt securities held by PNM, had the following final maturities:

	Fair Value
	(In thousands)
Within 1 year	$	13,996
After 1 year through 5 years	68,108
After 5 years through 10 years	68,904
After 10 years through 15 years	9,485
After 15 years through 20 years	12,174
After 20 years	45,695
	$	218,362

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. 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 three months ended March 31, 2019 or the year ended December 31, 2018.

For investment securities, Level 2 and Level 3 fair values are provided by fund managers utilizing a pricing service. For Level 2 fair values, 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. Fair values of Level 2 investments in mutual funds are equal to net asset value. Level 3 investments are comprised of corporate term loans. 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. The valuation of Level 3 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. Management of the Company independently verifies the information provided by pricing services.

40

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy along with gross unrealized gains on investments in available-for-sale debt securities.

				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)		Unrealized Gains
	(In thousands)
March 31, 2019
Cash and cash equivalents	$	10,339		$	10,339	$	—		$	—
Equity securities:
Corporate stocks, common	36,025			36,025		—			—
Corporate stocks, preferred	8,138			1,854		6,284			—
Mutual funds and other	78,699			78,688		11			—
Available-for-sale debt securities:
U.S. Government	36,153			25,074		11,079			—		$	1,489
International Government	11,577			46		11,531			—		345
Municipals	49,160			—		49,160			—		1,337
Corporate and other	121,472			842		118,543			2,087		5,831
	$	351,563		$	152,868	$	196,608		$	2,087	$	9,002
Commodity derivative assets	$	3,351		$	—	$	3,351		$	—
Commodity derivative liabilities	(3,415		)	—		(3,415		)	—
Net	$	(64	)	$	—	$	(64	)	$	—
December 31, 2018
Cash and cash equivalents	$	11,472		$	11,472	$	—		$	—
Equity securities:
Corporate stocks, common	32,997			32,997		—			—
Corporate stocks, preferred	7,258			1,654		5,604			—
Mutual funds and other	70,777			70,777		—			—
Available-for-sale debt securities:
U.S. Government	29,503			18,662		10,841			—		$	1,098
International Government	8,435			—		8,435			—		90
Municipals	53,642			—		53,642			—		489
Corporate and other	114,158			588		111,414			2,156		923
	$	328,242		$	136,150	$	189,936		$	2,156	$	2,600
Commodity derivative assets	$	3,594		$	—	$	3,594		$	—
Commodity derivative liabilities	(3,688		)	—		(3,688		)	—
Net	$	(94	)	$	—	$	(94	)	$	—

41

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

	Corporate Debt
	(In thousands)
Balance at December 31, 2018	$	2,156
Actual return on assets sold during the period	(49		)
Actual return on assets still held at period end	54
Purchases	414
Sales	(488		)
Balance at March 31, 2019	$	2,087
Balance at December 31, 2017	$	—
Actual return on assets sold during the period	(3		)
Actual return on assets still held at period end	(11		)
Purchases	2,724
Sales	(359		)
Balance at March 31, 2018	$	2,351

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

					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
March 31, 2019	(In thousands)
PNMR
Long-term debt	$	2,944,241	$	3,023,159	$	—	$	3,023,159	$	—
Other investments	$	299	$	299	$	299	$	—	$	—
PNM
Long-term debt	$	1,706,873	$	1,744,864	$	—	$	1,744,864	$	—
Other investments	$	93	$	93	$	93	$	—	$	—
TNMP
Long-term debt	$	798,941	$	838,705	$	—	$	838,705	$	—
Other investments	$	206	$	206	$	206	$	—	$	—
December 31, 2018
PNMR
Long-term debt	$	2,670,111	$	2,703,810	$	—	$	2,703,810	$	—
Other investments	$	297	$	297	$	297	$	—	$	—
PNM
Long-term debt	$	1,656,490	$	1,668,736	$	—	$	1,668,736	$	—
Other investments	$	91	$	91	$	91	$	—	$	—
TNMP
Long-term debt	$	575,398	$	597,236	$	—	$	597,236	$	—
Other investments	$	206	$	206	$	206	$	—	$	—

42

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(8) 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. The Company has not awarded stock options since 2010. Certain restricted stock awards are subject to achieving performance or market targets. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

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, awards to employees 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. Awards of restricted stock to non-employee members of the Board are expensed over a one-year vesting period.

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 over the performance period as required service is provided 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. At March 31, 2019, PNMR had unrecognized expense related to stock awards of $6.5 million, which is expected to be recognized over an average of 1.74 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. GAAP requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as operating cash flows when used to reduce income taxes payable.

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:

	Three Months Ended March 31,
Restricted Shares and Performance Based Shares	2019			2018
Expected quarterly dividends per share	$	0.2900		$	0.2650
Risk-free interest rate	2.50		%	2.39		%
Market-Based Shares
Dividend yield	2.59		%	2.96		%
Expected volatility	19.55		%	19.12		%
Risk-free interest rate	2.51		%	2.36		%

43

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the three months endedMarch 31, 2019:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2018	166,651		$	32.93	81,000		$	11.94
Granted	114,611		$	36.48	—		$	—
Exercised	(118,427	)	$	30.97	(78,000	)	$	11.92
Forfeited	—		$	—	—		$	—
Expired	—		$	—	—		$	—
Outstanding at March 31, 2019	162,835		$	36.86	3,000		$	12.38

PNMR’s stock-based compensation program provides for performance and market targets through 2021. In February 2019, the Board approved amendments to exclude certain impacts of the Tax Act on performance metrics for the performance periods ending in 2018 and 2019. These amendments did not impact the Company’s calculation of grant date fair values under the plans, but did increase actual achievement levels for the performance period ending in 2018 from below “threshold” levels to below “target” levels and anticipated achievement levels for the performance period ending in 2019 from below “target” levels to the “maximum” level. Included as granted and exercised in the table above are 47,279 previously awarded shares that were earned for the 2016 through 2018 performance measurement period and ratified by the Board in February 2019 (based upon achieving market targets at below “threshold” levels, weighted at 40%, and performance targets at above “target” levels, together weighted at 60%). Excluded from the table above are maximums of 130,302, 146,941, and 135,678 shares for the three-year performance periods ending in 2019, 2020, and 2021 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she was to receive 17,953 of the total shares if PNMR achieved specific performance targets at the end of 2017. The specified performance target was achieved at the end of 2017 and the Board ratified her receiving 17,953 shares in February 2018. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

At March 31, 2019, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $0.1 million with a weighted-average remaining contract life of 1.0 years. At March 31, 2019, 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:

	Three Months Ended March 31,
Restricted Stock	2019		2018
Weighted-average grant date fair value	$	36.48	$	29.03
Total fair value of restricted shares that vested (in thousands)	$	5,314	$	7,162
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)	$	2,582	$	2,711

44

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(9) Financing

The Company’s financing strategy includes both short-term and long-term borrowings. The Company utilizes short-term revolving credit facilities, as well as cash flows from operations, to provide funds for both construction and operating expenditures. Depending on market and other conditions, the Company will periodically sell long-term debt or enter into term loan arrangements and use the proceeds to reduce borrowings under the revolving credit facilities or refinance other debt. Each of the Company’s revolving credit facilities and term loans contain a single financial covenant that requires the maintenance of a debt-to-capitalization ratio. For the PNMR and PNMR Development agreements, this ratio must be maintained at less than or equal to 70%, and for the PNM and TNMP agreements, this ratio must be maintained at less than or equal to 65%. The Company’s revolving credit facilities and term loans generally also contain 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. Additional information concerning financing activities is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Financing Activities

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 was required to post in connection with permits relating to the operation of the San Juan mine. On March 15, 2019, WSJ LLC acquired the assets of SJCC following the bankruptcy of Westmoreland. WSJ LLC assumed the obligations to PNMR under the letters of credit support (Note 11).

On April 9, 2018, PNMR Development deposited $68.2 million with PNM related to potential transmission network interconnections, which was classified as a cash inflow from financing activities on PNM’s Condensed Consolidated Statements of Cash Flows in the second quarter of 2018. PNM used the deposit to repay intercompany borrowings. PNM is required to pay interest to PNMR Development to the extent work under the interconnections has not been performed. During the three months ended March 31, 2019, PNM recognized $0.9 million of interest expense under the agreement. At March 31, 2019, PNM’s remaining obligation under the interconnection agreement with PNMR Development of $68.2 million, excluding unpaid interest, is reflected in other deferred credits on PNM’s Condensed Consolidated Balance Sheets. As required by GAAP, all intercompany transactions related to this deposit have been eliminated on PNMR’s Condensed Consolidated Financial Statements.

On January 18, 2019, PNM entered into a $250.0 million term loan agreement (the “PNM 2019 Term Loan”) among PNM, the lenders identified therein, and U.S. Bank N.A., as administrative agent. PNM used the proceeds of the PNM 2019 Term Loan to repay the PNM 2017 Term Loan, to reduce short-term borrowings under the PNM Revolving Credit Facility, and for general corporate purposes. The PNM 2019 Term Loan bears interest at a variable rate and must be repaid on or before July 17, 2020.

On February 26, 2019, TNMP entered into the TNMP 2019 Bond Purchase Agreement with institutional investors for the sale of $305.0 million aggregate principal amount of four series of TNMP first mortgage bonds (the “TNMP 2019 Bonds”) offered in private placement transactions. TNMP issued $225.0 million of TNMP 2019 Bonds on March 29, 2019 and used the proceeds to repay TNMP’s $172.3 million9.50% first mortgage bonds at their maturity on April 1, 2019, as well as to repay borrowings under the TNMP Revolving Credit Facility and for other general corporate purposes. TNMP will issue the remaining $80.0 million of TNMP 2019 Bonds on or before July 1, 2019 and will use the proceeds from that issuance to repay borrowings under the TNMP Revolving Credit Facility and for other general corporate purposes. The issuance of the remaining TNMP 2019 Bonds is subject to the satisfaction of customary conditions, and the TNMP 2019 Bonds are subject to continuing compliance with the representations, warranties and covenants of the TNMP 2019 Bond Purchase Agreement. The terms of the TNMP 2019 Bond Purchase Agreement include customary covenants, including a covenant that requires TNMP to maintain a debt-to-capitalization ratio of less than or equal to 65%, customary events of default, a cross-default provision, and a change-of-control provision. TNMP will have the right to redeem any or all of the TNMP 2019 Bonds prior to their respective maturities, subject to payment of a customary make-whole premium. In accordance with GAAP, borrowings under the $172.3 million9.50% TNMP first mortgage bonds are reflected as being long-term in the Condensed Consolidated Balance Sheets at December 31, 2018 since TNMP demonstrated its intent and ability to re-finance the agreement on a long-term basis. These bonds are reflected in current maturities of long-term debt on the Condensed Consolidated Balance Sheets at March 31, 2019 since the proceeds from the issuance of $225.0 million of TNMP 2019 Bonds, net of amounts used to repay short-term debt, are reflected in cash and cash equivalents.

45

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Information concerning the funding dates, maturities and interest rates on the TNMP 2019 Bonds issued in March 2019 and to be issued on or before July 1, 2019 is as follows:

Funding Date	Maturity Date	Principal Amount		Interest Rate
		(In millions)
March 29, 2019	March 29, 2034	$	75.0	3.79	%
March 29, 2019	March 29, 2039	75.0		3.92	%
March 29, 2019	March 29, 2044	75.0		4.06	%
		225.0
July 1, 2019	July 1, 2029	80.0		3.60	%
		$	305.0

At March 31, 2019, variable interest rates were 3.29% on the $50.0 million PNMR 2018 Two-Year Term Loan, which matures in December 2020, 3.13% on the $250.0 million PNM 2019 Term Loan, which matures in July 2020, 3.20% on the $35.0 million TNMP 2018 Term Loan, which matures in July 2020, and 3.30% on the $90.0 million PNMR Development Term Loan, which matures in November 2020.

Short-term Debt and Liquidity

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. Both facilities currently expire on October 22, 2023 but contain options to be extended through October 2024, subject to approval by a majority of the lenders. One lender whose commitment was $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. On April 25, 2019, a new lender assumed the commitments of the non-extending lender under the PNMR and PNM Revolving Credit Facilities. PNM also has the $40.0 million PNM 2017 New Mexico Credit Facility that expires on December 12, 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 and matures on September 23, 2022.

On February 22, 2019, PNMR Development amended its $24.5 million revolving credit facility to increase the capacity to $25.0 million and to extend the term until February 24, 2020. The PNMR Development Revolving Credit 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 uses the facility to finance its participation in NMRD and for other activities.

Short-term debt outstanding consisted of:

	March 31,		December 31,
Short-term Debt	2019		2018
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	—	$	32,400
PNM 2017 New Mexico Credit Facility	—		10,000
	—		42,400
TNMP Revolving Credit Facility	—		17,500
PNMR:
PNMR Revolving Credit Facility	62,200		20,000
PNMR 2018 One-Year Term Loan	150,000		150,000
PNMR Development Revolving Credit Facility	11,600		6,000
	$	223,800	$	235,900

46

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At March 31, 2019, the weighted average interest rate was 3.74% for the PNMR Revolving Credit Facility, 3.24% for the PNMR 2018 One-Year Term Loan, and 3.49% for the PNMR Development Revolving Credit Facility.

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $4.7 million, $2.5 million, and $0.7 million at March 31, 2019 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of March 31, 2019 and December 31, 2018, TNMP had zero and $0.1 million of intercompany borrowings from PNMR, PNM had zero and $19.8 million of intercompany borrowings from PNMR, and PNMR Development had $3.1 million and zero of intercompany borrowings from PNMR.

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 for three separate tranches, each of $50.0 million, of its variable rate debt. These hedge agreements are accounted for as cash flow hedges. These hedge agreements had fair values aggregating $1.4 million at March 31, 2019 that is included in other deferred charges and $1.0 million at December 31, 2018 that is included in other current assets on the Condensed Consolidated Balance Sheets. As discussed in Note 3, changes in the fair value of the cash flow hedge are deferred in AOCI and amounts reclassified to the Condensed Consolidated Statement of Earnings are recorded in interest charges. 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. On January 1, 2019, the Company adopted Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. Adoption of the updated standard did not have a significant impact on these cash flow hedges.

At May 3, 2019, PNMR, PNM, TNMP, and PNMR Development had availability of $239.4 million, $397.5 million, $45.7 million, and $9.9 million under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $40.0 million of availability under the PNM 2017 New Mexico Credit Facility. Total availability at May 3, 2019, on a consolidated basis, was $732.5 million for PNMR. As of May 3, 2019, PNM and TNMP had no borrowings from PNMR under their intercompany loan agreements. At May 3, 2019, PNMR, PNM, and TNMP had invested cash of $0.9 million, $9.0 million, and none.

The Company’s debt arrangements have various maturities and expiration dates. As discussed above, on February 26, 2019 TNMP entered into the TNMP 2019 Bond Purchase Agreement providing for the issuance of an aggregate of $305.0 million of TNMP 2019 Bonds. TNMP issued $225.0 million of the TNMP 2019 Bonds on March 29, 2019 and used a portion of the proceeds from that issuance to repay TNMP’s $172.3 million9.50% first mortgage bonds at their maturity on April 1, 2019. TNMP will issue the remaining $80.0 million of TNMP 2019 Bonds on or before July 1, 2019 and will use the proceeds from that issuance to repay borrowings under the TNMP Revolving Credit Facility and for other general corporate purposes. In addition, the $150.0 million PNMR 2018 One-Year term loan will mature in December 2019. The Company has no other long-term debt due through March 31, 2020. Additional information on debt maturities is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

(10) Pension and Other Postretirement Benefit Plans

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. In accordance with GAAP, the Company presents the service cost component of its net periodic benefit costs in administrative and general expenses and the non-service costs components in other income (deductions), net of amounts capitalized or deferred to regulatory assets and liabilities, on the Condensed Consolidated Statements of Earnings. PNM and TNMP receive a regulated return on the amounts funded for pension and OPEB plans in excess of accumulated periodic cost or income to the extent included in retail rates (a “prepaid pension asset”).

Additional information concerning pension and OPEB plans is contained in Note 11 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Annual net periodic benefit cost for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year.

47

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM Plans

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

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2019			2018			2019			2018			2019		2018
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	13		$	21		$	—	$	—
Interest cost	6,294			6,068			829			860			162		155
Expected return on plan assets	(8,527		)	(8,672		)	(1,318		)	(1,353		)	—		—
Amortization of net (gain) loss	3,880			4,087			169			588			79		90
Amortization of prior service cost	(241		)	(241		)	(99		)	(416		)	—		—
Net periodic benefit cost	$	1,406		$	1,242		$	(406	)	$	(300	)	$	241	$	245

PNM did not make any contributions to its pension plan trust in the three months ended March 31, 2019 and 2018 and does not anticipate making any contributions to the pension plan in 2019-2021, but expects to contribute $1.3 million in 2022 and $22.9 million in 2023, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.2% to 4.6%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made no contributions to the OPEB trust in the three months ended March 31, 2019 and 2018. PNM does not expect to make any contributions to the OPEB trust in 2019-2023.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $0.5 million in the three months ended March 31, 2019 and 2018 and are expected to total $1.5 million during 2019 and $5.6 million for 2020-2023.

TNMP Plans

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

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2019			2018			2019			2018			2019		2018
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	13		$	33		$	—	$	—
Interest cost	672			656			113			119			8		7
Expected return on plan assets	(967		)	(991		)	(129		)	(135		)	—		—
Amortization of net (gain) loss	235			272			(110		)	(56		)	4		4
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost	$	(60	)	$	(63	)	$	(113	)	$	(39	)	$	12	$	11

TNMP did not make any contributions to its pension plan trust in the three months ended March 31, 2019 and 2018 and does not anticipate making any contributions in 2019-2023, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.2% to 4.6%. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions of zero and $0.3 million to the OPEB trust in the three months ended March 31, 2019 and 2018. TNMP does not expect to make contributions to the OPEB

48

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

trust during the period 2019-2023. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three months ended March 31, 2019 and 2018 and are expected to total $0.1 million during 2019 and $0.3 million in 2020-2023.

(11) Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. In addition, the Company 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 12) 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. 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 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.

Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Commitments and Contingencies Related to the Environment

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 the DOE entered into a settlement agreement that establishes a process for the payment of claims for costs incurred through December 31, 2019. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. PNM records estimated claims on a quarterly basis. The benefit from the claims is passed through to customers under the FPPAC to the extent applicable to NMPRC regulated operations.

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 nuclear fuel is consumed. At March 31, 2019 and December 31, 2018, PNM had a liability for interim storage costs of $12.5 million and $12.4 million, which is included in other deferred credits.

49

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

The Energy Transition Act

On March 22, 2019, the Governor signed into New Mexico state law Senate Bill 489, known as the Energy Transition Act (“ETA”). The ETA becomes effective as of June 14, 2019 and sets a statewide standard that requires investor-owned electric utilities to have specified percentages of their electric-generating portfolios be provided from renewable and zero-carbon generating resources. Prior to the enactment of the ETA, the REA established a mandatory RPS requiring utilities to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also amends sections of the REA to allow for the recovery of undepreciated investments and decommissioning costs related to qualifying EGUs that the NMPRC has required be removed from retail jurisdictional rates, provided replacement resources to be included in retail rates have lower or zero-carbon emissions. The ETA requires the NMPRC to review and approve utilities’ annual renewable portfolio plans to ensure compliance with the RPS. The ETA also directs the New Mexico Environmental Improvement Board to adopt standards of performance that limit CO₂ emissions to no more than 1,100 lbs. per MWh beginning January 1, 2023 for new or existing coal-fired EGUs with original installed capacities exceeding 300 MWs.

The ETA provides for a transition from fossil-fuel generation resources to renewable and other carbon-free resources through certain provisions relating to the abandonment of coal-fired generating facilities. These provisions include the use of “energy transition bonds,” which are designed to be highly rated bonds that can be issued by qualifying utilities to finance certain costs of abandoning coal-fired facilities that are retired prior to January 1, 2023, for facilities operated by a “qualifying utility,” or prior to January 1, 2032 for facilities that are not operated by the qualifying utility. The amount of energy transition bonds that can be issued to recover abandonment costs is limited to the lesser of $375.0 million or 150% of the undepreciated investment of the facility as of the abandonment date. Proceeds provided by energy transition bonds must be used only for purposes related to providing utility service to customers and to pay “financing costs” (as defined by the ETA). These costs may include plant decommissioning and coal mine reclamation costs provided those costs have not previously been recovered from customers or disallowed by the NMPRC or by a court order. Proceeds from energy transition bonds may also be used to fund severances for employees of the retired facility and related coal mine and to promote economic development, education and job training in areas impacted by the retirement of the coal-fired facilities. Energy transition bonds must be issued under an NMPRC approved financing order, are secured by “energy transition property,” are non-recourse to the issuing utility, and must be repaid by a non-bypassable charge paid by all customers of the issuing utility. These customer charges are subject to an adjustment mechanism designed to provide for timely and complete payment of principal and interest due under the energy transition bonds.

The ETA also provides that utilities must obtain NMPRC approval of competitively procured replacement resources. In determining whether to approve replacement resources, the NMPRC must give preference to resources with the least environmental impacts, those with higher ratios of capital costs to fuel costs, and those able to reduce the cost of reclamation and use for lands previously mined within the county of the EGU to be abandoned. Replacement resources will be subject to local taxes or equivalent payments in lieu of taxes and are defined to mean up to 450 MW of nameplate capacity, provided such resources are located in the same school district as the abandoned facility, are necessary to maintain reliable service, and are in the public interest as determined by the NMPRC. The ETA also provides for the procurement of energy storage facilities and gives utilities discretion to maintain and control these systems to ensure reliable and efficient service.

The effectiveness of the ETA will have a significant impact on PNM’s future generation portfolio, including PNM’s planned retirement of SJGS in 2022. See December 2018 Compliance Filing below. PNM cannot predict the full impact of the ETA or the outcome of its potential future financing and generating resource abandonment and replacement resource filings with the NMPRC.

50

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 was demonstrated that the emissions from these sources caused or contributed to visibility impairment in any Class I area, then BART must have been installed by the beginning of 2018. For all future SIP planning periods, 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. On December 20, 2018, EPA released a new guidance document on tracking visibility progress for the second planning period. EPA is allowing states discretion to develop SIPs that may differ from EPA’s guidance as long as they are consistent with the CAA and other applicable regulations. SIPs for the second compliance period are due in July 2021. EPA’s decision to revisit the 2017 rule is not a determination on the merits of the issues raised in the petitions. PNM is evaluating the potential impacts of these matters.

SJGS

December 2018 Compliance Filing –As discussed in Note 16 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, in December 2015 PNM received NMPRC approval for a plan to comply with the EPA regional haze rule at SJGS. Among other things, the NMPRC’s December 2015 order required that, no later than December 31, 2018, PNM make a filing with the NMRPC to determine the extent to which SJGS should continue serving PNM’s customers’ needs after June 30, 2022, including PNM’s recommendation and supporting testimony and exhibits (the “December 2018 Compliance Filing”). The December 2018 Compliance Filing was required to be made before PNM entered into a binding commitment for post-2022 coal supply but after PNM received firm pricing and other terms for the supply of coal at SJGS, unless PNM did not intend to pursue an agreement for post-2022 coal supply at SJGS. The NMPRC’s December 2015 order also indicated that, if SJGS Unit 4 is abandoned with undepreciated investment on PNM’s books, PNM is prohibited from recovering the undepreciated investment of its 132 MW interest and required that PNM’s 65 MW interest in SJGS Unit 4 be treated as excluded merchant plant. PNM is currently depreciating all its investments in SJGS through 2053, which reflects the period of time over which the NMPRC has authorized PNM to recover its investment in SJGS from New Mexico retail customers.

PNM submitted the December 2018 Compliance Filing to the NMPRC on December 31, 2018 indicating that, consistent with the conclusions reached in PNM’s 2017 IRP (Note 12), PNM’s customers would benefit from the retirement of PNM’s share of SJGS after the current SJGS CSA expires in mid-2022. The December 2018 Compliance Filing also indicates that, pursuant to the terms of the agreements governing SJGS, all of the SJGS owners except for Farmington have provided written notice that they do not intend to extend the SJGS operating agreements beyond their June 30, 2022 expiration dates, and that PNM has provided written notice to SJCC that PNM does not intend to extend the SJGS CSA beyond June 30, 2022 or to negotiate a new coal supply agreement on behalf of the other SJGS participants. The December 2018 Compliance Filing also requested the NMPRC accept the filing as compliant with the December 2015 order and indicated that PNM anticipates it will have sufficient information by the end of the second quarter of 2019 to support a consolidated application seeking NMPRC approval to retire PNM’s share of

51

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

SJGS in 2022 and for approval of CCNs, PPAs, or other applicable approvals, for replacement capacity resources. On January 10, 2019, the NMPRC opened a docket to determine whether the NMPRC should grant PNM’s request to accept the December 2018 Compliance Filing and take no further action pending PNM submitting a formal consolidated abandonment and replacement resources application, or whether the NMPRC should immediately establish a formal procedural schedule regarding the abandonment of SJGS. The NMPRC received responses from parties regarding the initial order and, on January 30, 2019, approved an order initiating a proceeding and requiring PNM to submit an application for the abandonment of PNM’s share of SJGS by March 1, 2019. On February 7, 2019, PNM filed a motion requesting the NMPRC vacate the January 30, 2019 order and extend the deadline for PNM’s abandonment filing until the end of the second quarter of 2019, which was deemed denied. On February 27, 2019, PNM filed a petition with the NM Supreme Court stating that the requirements of the January 30, 2019 order exceed the NMPRC’s authority by, among other things, mandating PNM to make a filing that is legally voluntary, and that the order is contrary to NMPRC precedent which requires abandonment applications to also include identified replacement resources and other information that would not be available to PNM by March 1, 2019. PNM’s petition also requested the NM Supreme Court stay the January 30, 2019 order until after June 14, 2019. On March 1, 2019, the NM Supreme Court granted a temporary stay of the NMPRC’s order to consider the merits of PNM’s petition after receiving responses.  On March 19, 2019, the NMPRC and NEE filed responses supporting the NMPRC’s authority to order PNM to initiate a proceeding. Other parties to the case filed responses supporting a stay of the NMPRC’s order and indicating that the abandonment filing should be subject to recently enacted changes in New Mexico state law. See additional discussion of the ETA above. PNM cannot predict the outcome of this matter.

GAAP requires that long-lived assets be tested for impairment when events or changes in circumstances indicate that their carrying value may not be recoverable. The test must consider only those cash flows that are directly associated with the long-lived asset, or group of assets, and requires the evaluation be performed at the lowest level for which identifiable cash flows are largely independent of other cash flows within the asset group. As of December 31, 2018, PNM evaluated the events surrounding its future participation in SJGS and determined that it is more likely than not that PNM’s share of SJGS will be retired in 2022. As a result, PNM performed an impairment analysis that assumed SJGS would not continue to operate through 2053, as previously approved by the NMPRC. PNM’s impairment analysis indicated that, pursuant to the NMPRC’s December 16, 2015 order, PNM’s undepreciated 132 MW interest in SJGS Unit 4 at June 30, 2022 will not be recovered from customers; that the estimated future cash flows expected to result from the operation of SJGS Unit 4 through June 30, 2022 are not sufficient to provide for recovery of PNM’s 65 MW merchant interest in the facility; and that it is unlikely PNM will be able to sell or transfer its interests in SJGS to third parties at amounts sufficient to provide for their recovery. As a result, as of December 31, 2018, PNM recorded a pre-tax impairment of its investment in SJGS of approximately $35.0 million, which is reflected as regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings in the 2018 Annual Reports on Form 10-K. This amount includes the entire $11.9 million carrying value of PNM’s 65 MW interest in SJGS Unit 4 as of December 31, 2018 and $23.1 million of estimated undepreciated investments in PNM’s 132 MW jurisdictional interest as of June 30, 2022 that will not be recovered from customers. The carrying value of PNM’s remaining undepreciated investments in SJGS, which PNM will seek to recover from customers in the event of an early retirement of the facility, is $371.6 million as of March 31, 2019. See additional discussion regarding the increase in PNM’s estimated liability for coal mine reclamation below.

The December 2018 Compliance Filing and the 2017 IRP are not final determinations of PNM’s future generation portfolio.  Retiring PNM’s share of SJGS will require future NMPRC approval. PNM will also be required to obtain NMPRC approval of replacement power resources through CCN, PPA, or other applicable filings. The financial impact of an early retirement of SJGS and the NMPRC approval process are influenced by many factors outside of PNM’s control, including the economic impact of a potential SJGS abandonment filing on the area surrounding that plant and the related mine, as well as the overall political and economic conditions of New Mexico. Other items that impact the economic viability of SJGS include the financial impact of climate change regulation or legislation, other environmental regulations, the result of litigation, and other business considerations or the ability or willingness of individual participants to continue participation in the plant. Furthermore, PNM’s application for the abandonment of SJGS, related financing, and for associated replacement resources would be significantly influenced by the requirements of the ETA. PNM will seek full recovery of its remaining undepreciated investments and other costs necessary to retire the facility and for replacement resources in that filing.

NEE Complaint – 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. On January 31, 2018, NEE filed a motion

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asking the NMPRC to investigate whether PNM’s relationship with WSJ, in light of Westmoreland’s financial condition, could be harmful to PNM’s customers. PNM responded requesting the NMPRC deny the motion and that NEE’s prior complaint be dismissed. On May 23, 2018, PNM filed its response to the NMPRC staff’s comments requesting additional information about the financing and noting that the Westmoreland Loan was paid in full on May 22, 2018. On October 11, 2018, PNM filed a supplemental response notifying the NMPRC that Westmoreland had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code on October 9, 2018. PNM’s supplemental response indicated Westmoreland had agreed to terms with its secured creditors that allowed it to continue to fund normal-course operations and to continue to serve its customers during the course of the bankruptcy case. As discussed in Note 6, on March 15, 2019, Westmoreland announced that it had emerged from Chapter 11 bankruptcy as a privately held company owned and operated by a group of its former creditors. Under the reorganization, all the assets of SJCC were sold to WSJ LLC. The March 15, 2019 announcement indicated that mining operations will continue in the normal course of business. As successor entity to SJCC, WSJ LLC assumed all rights and obligations of Westmoreland including obligations to PNM under the SJGS CSA. The NMPRC has taken no further action on NEE’s complaints. PNM cannot predict the outcome of these matters.

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 dismissal in the United States Court of Appeals for the Ninth Circuit on November 9, 2017, and the court granted their subsequent motion to expedite the appeal. Oral arguments for the appeal were held on March 7, 2019. 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 NSPS 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

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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, 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. In a separate but related action, on December 18, 2017, EPA released an advanced NOPR addressing GHG guidelines for existing electric utility generating units. On August 31, 2018, EPA published a proposed rule, which is informally known as the Affordable Clean Energy rule, to replace the Clean Power Plan. The proposed Affordable Clean Energy rule, among other things, would establish guidelines that replace the “outside-the-fenceline” control measures and specific numerical emission rates for existing EGUs. These measures are replaced with a list of “candidate technologies” for heat rate improvement measures, which include both technologies and operational changes that EPA has identified as Best System of Emission Reduction (“BSER”). States would determine which of the candidate technologies to apply to each coal-fired unit and establish standards of performance based on the degree of emission reduction achievable through application of the selected BSER.  States will have three years from when the rule is finalized to submit a plan to EPA. EPA will then have one year to determine if each proposed plan is acceptable. If states do not submit a plan, or if a state’s plan is not acceptable, EPA will develop a federal plan for the state to implement.  EPA is also proposing revisions to the NSR program that would provide coal-fired power plants more latitude to make efficiency improvements consistent with BSER without triggering NSR permit requirements. Comments on the proposed Affordable Clean Energy rule were due to EPA by October 31, 2018.

The proposed Affordable Clean Energy rule and the proposed 2015 federal plan released concurrently with the Clean Power Plan are 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 proposed Affordable Clean Energy rule or the Clean Power Plan, should it ultimately be sustained, on the Navajo Nation. In addition, in the proposed 2015 federal plan, EPA included a finding “that it is necessary or appropriate” to implement a section 111(d) federal plan for affected EGUs located in Native American lands. APS and PNM filed separate comments with EPA on EPA’s draft 2015 federal plan 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 if the Affordable Clean Energy rule, the Clean Power Plan, or other future GHG reduction rulemaking are ultimately implemented and EPA determines that a federal plan is necessary or appropriate for the Navajo Nation.

On December 20, 2018, EPA published in the Federal Register a proposed rule that would revise the carbon pollution standards rule published in October 2015 for fossil fueled power plants. The proposed rule would revise the standards for coal-fired EGUs based on a revised BSER determination that would result in less stringent CO₂ emission performance standards for new, reconstructed, and modified fossil-fueled power plants. EPA is not proposing any changes nor reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. Comments on the proposal were due on March 18, 2019.

PNM’s review of the GHG emission reductions standards under the proposed Affordable Clean Energy rule, the revised proposed Carbon Pollution Standards rule, and the Clean Power Plan is ongoing and the assessment of its impacts will depend on the proposed repeal of the Clean Power Plan, promulgation of the Affordable Clean Energy rule and the revised proposed Carbon Pollution Standards rule, other future GHG reduction rulemaking, litigation of any final rule, and other actions the Trump Administration is taking through judicial and regulatory proceedings. As discussed above, SJGS and Four Corners may also be required to comply with additional GHG restrictions issued by the New Mexico Environmental Improvement Board pursuant to the recently enacted ETA. PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance, if any.

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National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants reasonably anticipated to endanger public health or welfare. 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 standard while retaining the annual standards for NOx and SO₂ and the 24-hour SO₂ standard. EPA also updated the final particulate matter standard in 2012 and updated the ozone standard in 2015.

NOx Standard – On April 18, 2018, EPA published the final rule to retain the current primary health-based NOx standards of which NO₂ is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO₂ standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018.

SO₂ Standard – 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. This characterization would result in these areas being designated as attainment, nonattainment, or unclassifiable 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 imposed deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO₂ emissions. The settlement resulted from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree required, among other things, that EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule by December 2020.  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 its formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO₂ standard. On June 27, 2018, NMED submitted the first annual report for SJGS as required by the Data Requirements Rule. The report recommends that no further modeling is warranted at this time due to decreased SO₂ emissions.

On February 25, 2019, EPA announced its final decision to retain without changes the primary health-based NAAQS for SOx. Specifically, EPA will retain the current 1-hour standard for SO₂, which is 75 parts per billion (“ppb”), based on the 3-year average of the 99th percentile of daily maximum 1-hour SO₂ concentrations.  SO₂ is the most prevalent SOx compound and is used as the indicator for the primary SOx NAAQS.

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 required the installation of SNCRs. The revised permit also requires the reduction of SO₂ emissions 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, SO_2, and particulate matter. These reductions 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.

Ozone Standard – On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 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 important 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.

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On February 25, 2016, EPA released guidance on area designations for ozone, which states used to determine their initial designation recommendations by October 1, 2016. NMED published its 2015 Ozone NAAQS Designation Recommendation Report on September 2, 2016. In New Mexico, EPA 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 NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. According to NMED’s website, “If emissions from Mexico keep New Mexico from meeting the standards, the New Mexico area could remain 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, San Juan County, New Mexico, where SJGS and Four Corners are located, is designated as attainment/unclassifiable. EPA designated a small area in Dona Ana County as marginal non-attainment.  On April 30, 2018, EPA completed additional area designations for the 2015 ozone standards. In a related matter, EPA published a final rule on March 9, 2018 establishing air quality thresholds that define the classifications assigned to all non-attainment areas for ozone NAAQS. The final rule also establishes the timing of attainment dates for each non-attainment area classification, which are marginal, moderate, serious, severe, or extreme. The rule became effective May 8, 2018.

NMED is required to submit an infrastructure and transport SIP that provides the basic air quality management program to implement the revised ozone standard. This plan is generally due within 36 months from the date the NAAQS is promulgated. The NMED has published a proposed certification that New Mexico currently has an adequate, federally-approved SIP that addresses elements of the CAA Section 110(a)(2) infrastructure SIP, as applicable to the 2015 ozone NAAQS. The purpose of the proposed certification is to confirm to EPA that New Mexico has the required “infrastructure” in place under the current SIP to implement, maintain, and enforce the revised 2015 ozone NAAQS. Comments on the proposed certification were due by October 29, 2018. State ozone attainment plans are generally due within five to six years from the date of the ozone NAAQS promulgation and are planned for submittal in 2020 and 2021.

PNM does not believe there will be material impacts to its facilities as a result of NMED’s non-attainment 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, PNM is unable to predict what impact the adoption of these standards may have on Four Corners. PNM cannot predict the outcome of this matter.

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 challenged several unrelated mining plan modification approvals, which were each separately approved by OSM.  WEG alleged 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 sought 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 concerned 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 NM District Court. 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

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resource data submittal phase was completed in November 2017. The draft EIS was made available in May 2018 and was subject to a public comment period that ended on July 9, 2018. The Notice of Availability for the final EIS was published in the Federal Register and became available on the OSM website on March 15, 2019. NEPA requires OSM to identify a preferred alternative in the final EIS and prepare a recommendation to the Assistant Secretary of Land and Minerals Management. OSM has selected a plan that would allow for continued mining that would extend beyond 2022 as the preferred alternative based on the impact analysis in the EIS. On May 1, 2019, OSM published its Record of Decision, which would allow for continued mining in the underground mine in annual quantities similar to those being currently being provided.  The OSM’s Record of Decision is subject to additional review and approval.  PNM cannot predict the outcome of this matter.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Nation and is held under easements granted by the federal government, as well as agreements with the Navajo Nation which grant each of the owners the right to operate on the site. 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 became effective October 14, 2014.

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

The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is 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.

On May 23, 2018, several environmental groups sued EPA Region IX in the United States Court of Appeals for the Ninth Circuit Court over EPA’s failure to timely reissue the Four Corners NPDES permit. The petitioners asked the court to issue a writ of mandamus compelling EPA Region IX to take final action on the pending NPDES permit by a reasonable date. EPA subsequently reissued the NPDES permit on June 12, 2018. The permit did not contain conditions related to the cooling water intake structure rule as EPA determined that the facility has achieved BTA for both impingement and entrainment by operating a closed-cycle recirculation system and no additional conditions are necessary. On July 16, 2018, several environmental groups filed a petition for review with the EPA’s Environmental Appeals Board concerning the reissued permit. The environmental groups alleged that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning certain revised effluent limitation guidelines, existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. On December 19, 2018, EPA

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withdrew the Four Corners NPDES permit in order to examine issues raised by the environmental groups. Withdrawal of the permit moots the appeal pending before the Environmental Appeals Board. The EPA’s Environmental Appeals Board thereafter dismissed the environmental groups’ appeal. EPA has indicated that, depending on the amount of public comments received concerning the permit proposal, it anticipates taking final action on a new NPDES permit by August 2019. Four Corners will continue to operate under the 2001 NPDES permit. PNM cannot predict the outcome of this matter or whether reconsideration will have a material impact on PNM’s financial position, results of operations or cash flows.

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 or revised NPDES permit.

On September 18, 2017, EPA published a final rule for postponement of certain compliance dates, which have not yet passed for the Effluent Limitations Guidelines rule, consistent with the EPA’s decision to grant reconsideration of that rule. The 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, although the new deadlines have been challenged in court.

The Effluent Limitations Guidelines rule was challenged in the U.S. Court of Appeals for the Fifth Circuit by numerous parties. On April 12, 2017, EPA signed a notice indicating its intent to reconsider portions of the rule and, on August 22, 2017, the Fifth Circuit issued an order severing the issues under reconsideration and holding the case in abeyance as to those issues. However, the court allowed challenges to other portions of the rule to proceed. On April 12, 2019, the Fifth Circuit granted those challenges and issued an opinion vacating several portions of the rule, specifically those related to legacy wastewater and leachate, for which the court deemed the standards selected by the EPA arbitrary and capricious.

Because SJGS is zero discharge for wastewater and is not required to hold a NPDES permit, it is expected that minimal to no requirements will be imposed. Reeves Station, a PNM-owned gas-fired generating station, discharges cooling tower blowdown to a publicly owned treatment plant and holds an NPDES permit. It is expected that minimal to no requirements will be imposed at Reeves Station.

EPA reissued an NPDES permit for Four Corners on June 12, 2018. EPA had determined that the guidelines in the 2015 rule are not applicable to this permit because the effective dates of the 2015 effluent guidelines rule were extended. On December 19, 2018, EPA withdrew the Four Corners NPDES permit in order to examine issues raised by several environmental groups. Four Corners will continue to operate under the 2001 NPDES permit. See Cooling Water Intake Structures above. 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, during the next NPDES permit renewal for Four Corners, which will be in 2023. PNM is unable to predict the outcome of these matters or a range of the potential costs of compliance.

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination

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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.  However, the renewed discharge permit requires that PNM conduct more frequent monitoring than originally anticipated, which resulted in an insignificant increase to the project cost estimate as of December 31, 2018.

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 monitoring activities conducted under the CAF to NMED on October 3, 2016. PNM completed all CAF-related work associated with the monitoring plan and received NMED’s approval. PNM’s contractor prepared a scope of work, which PNM and NMED approved, for the installation of additional monitoring wells and additional sampling of certain existing monitoring wells at the site. These activities were completed in June 2018. PNM’s contractor has commenced the next phase of work which includes the installation of up to 38 additional monitoring wells. Work is expected to be completed in mid-2019. Qualified costs of this work are eligible for payment through the CAF.

On March 28, 2019, PNM received notice from NMED that an abatement plan is required with respect to the site to address concentrations of previously identified compounds found in the groundwater. The abatement plan would include an investigation to define site conditions and provide data necessary to select and design an abatement option. PNM must submit its abatement plan to NMED by May 27, 2019 but has requested an extension to June 25, 2019. Under NMED regulations, NMED and PNM are required to publish information summarizing the source and magnitude of the pollution. NMED may also hold a public hearing if there is sufficient public interest.

PNM is unable to predict the outcome of these matters.

Coal Combustion Residuals Waste Disposal

CCRs consisting of fly ash, bottom ash, and gypsum generated from coal combustion and emission control equipment at SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCR impoundments or landfills. The NMMMD currently regulates mine reclamation activities at the San Juan mine, including placement of CCRs in the surface mine pits, with federal oversight by the OSM. APS disposes of CCRs in 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.

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EPA’s final coal ash rule, which became effective on October 19, 2015, included a non-hazardous waste determination for coal ash. The rule sets minimum criteria for existing and new CCR landfills and existing and new CCR 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 of RCRA, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the 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 requirements.

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 CCR rules under Subtitle D. Among other things, the WIIN Act provides for the establishment of state and EPA permit programs for CCRs, provides flexibility for states to incorporate the EPA final rule for CCRs 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 CCR 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 CCR 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 CCR provisions of the WIIN Act. There is no timeline for establishing either state or federal permitting programs. APS has sought 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 CCR regulations based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCRs, which were premised in part on the provisions of the WIIN Act. In light of the WIIN Act and the petitions for rulemaking, EPA is considering making additional changes to the CCR 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 CCR regulations and pursuant to an order issued by the DC Circuit, EPA and the industry groups argued the court should postpone adjudication until EPA completes the reconsideration process for the affected provision.

Pursuant to a June 24, 2016 order by the DC Circuit in litigation by industry and environmental groups challenging EPA’s CCR regulations, EPA is required to complete a rulemaking proceeding by June 2019 to address specific technical issues. On March 15, 2018, EPA proposed its Phase I Remand Rule that includes potential revisions to provide site-specific, risk-based tailoring of groundwater monitoring, corrective action and location restriction requirements of the CCR rule. EPA published the final rule on July 30, 2018. According to EPA, the July 30, 2018 rule constitutes “Phase One, Part One” of its ongoing reconsideration and revision of the April 17, 2015 coal ash rule. The final rule includes two types of revisions. The first revision extends the deadline to allow EGUs with unlined impoundments or that fail to meet the uppermost aquifer requirement to continue to receive coal ash until October 31, 2020. The second revision authorizes a “Participating State Director” or EPA, in lieu of a professional engineer, to approve suspension of groundwater monitoring and to issue certifications related to the location restrictions, design criteria, groundwater monitoring, remedy selection and implementation. The revisions also modify groundwater protection standards for certain constituents, which include cobalt, molybdenum, lithium, and lead without a maximum contamination level. EPA indicated that provisions in the March 2018 rule that are not addressed in the July 2018 final rule will be addressed in a subsequent rulemaking.

On August 21, 2018, the DC Circuit Court of Appeals issued its decision in the CCR litigation. The court denied EPA’s request to hold the case in abeyance; remanded the industry group’s challenges to the regulation of certain on-site CCR piles; denied relief for the remaining industry group’s claims, including the challenge to EPA’s authority to regulate inactive surface impoundments; and found for the environmental groups on their challenges to the ability of unlined impoundments to continue operating, the classification of certain unlined impoundments as “lined” units, and EPA’s failure to regulate legacy ponds. It

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(Unaudited)

remains unclear how the DC Circuit Court of Appeals decision will impact Four Corners as EPA has not yet taken regulatory action on remand to revise its CCR regulations consistent with the court’s order.

Based on this decision, on December 17, 2018, certain environmental groups filed an emergency motion with the D.C. Circuit to stay or summarily vacate EPA’s July 17, 2018 final rule extending the closure-initiation deadline for certain unlined CCR surface impoundments until October 2020. In response, EPA filed a motion to remand but not vacate that deadline extension regulation. On March 13, 2019, the court granted EPA’s motion for a voluntary remand without vacatur. As a result, the “Phase One, Part One” rule will remain in place while EPA reconsiders the rule on remand and continues its ongoing revisions to the CCR rule. This means that the October 31, 2020 deadline to initiate closure for unlined CCR impoundments and impoundments that fail the aquifer location restriction will remain in place while EPA completes a new rulemaking to reaffirm or establish a new deadline for initiating closure. PNM cannot predict the outcome of the D.C. Circuit’s consideration of these competing motions, and whether or how such a ruling would affect operations at Four Corners.

The CCR 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 and the determination by EPA that CCRs are non-hazardous. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCR regulation, including mine placement of CCRs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows. Based upon the requirements of the final rule, PNM conducted a CCR 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 would seek recovery from its ratepayers of all CCR costs for retail jurisdictional assets that are ultimately incurred. PNM does not expect the rule to have a material impact on operations, financial position, or cash flows.

As indicated above, CCRs at Four Corners are currently disposed of in ash ponds and dry storage areas. The CCR rule requires ongoing, phased groundwater monitoring. Utilities that own or operate CCR disposal units, such as those at Four Corners were required to collect 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 CCR rule’s standards, the rule required the initiation of an assessment monitoring program by April 15, 2018.  If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed. Four Corners completed an analysis that determined several of its CCR disposal units will need corrective action or will need to cease operations and initiate closure by October 2020. Four Corners anticipates it will complete its evaluation of these matters, including gathering additional groundwater data, soliciting public comment, and selecting potential actions, by the summer of 2019. At this time, PNM does not anticipate its share of the cost to complete these corrective actions or to close the CCR disposal units at Four Corners will have a significant impact on its operations, financial position, or cash flows.

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. In addition to coal delivered to meet the current needs of SJGS, PNM has prepaid SJCC for certain coal mined but not yet delivered to the plant site. At March 31, 2019 and December 31, 2018, prepayments for coal, which are included in other current assets, amounted to $26.3 million. Additional information concerning the coal supply for SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

In conjunction with the activities undertaken to comply with the CAA for SJGS, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS. On July 1, 2015, PNM and Westmoreland entered into a new coal supply agreement (the “SJGS CSA”), pursuant to which Westmoreland agreed to supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland agreed to provide CCR 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.

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(Unaudited)

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 CCR disposal and mine reclamation services were assigned to SJCC. As discussed in Note 6, with the closing of the sale of the assets of SJCC on March 15, 2019, WSJ LLC assumed the rights and obligations of SJCC under the SJGS CSA and the agreements for CCR disposal and mine reclamation services. Pricing under the SJGS CSA is primarily fixed, with adjustments to reflect changes in general inflation. The pricing structure takes into account that WSJ LLC has been paid for coal mined but not delivered.

PNM had 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, the SJGS CSA provides that PNM must have given written notice of that intent by July 1, 2018 and the parties must have agreed to the terms of the extension by January 1, 2019. In addition, the SJPPA obligates each SJGS participant to provide notice to the other participants whether they wish to extend the terms of the SJPPA and the SJGS CSA beyond June 30, 2022. In 2018, PNM, Los Alamos, UAMPS, and Tucson provided notice of their intent to exit SJGS in 2022 and Farmington gave notice that it wishes to continue SJGS operations and to extend the terms of both agreements. On November 30, 2018, PNM provided notice to Westmoreland that PNM does not intend to extend the term of the SJGS CSA or to negotiate a new coal supply agreement for SJGS, which will result in the current agreement expiring on its own terms on June 30, 2022. See December 2018 Compliance Filing above.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC was 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. As discussed in Note 6, on March 15, 2019, the assets owned by SJCC were sold to WSJ LLC, a subsidiary of Westmoreland Mining Holdings, LLC. Under the sale agreement, WSJ LLC assumed the rights and obligations of SJCC, including obligations to PNMR under the outstanding letters of credit.

Four Corners

APS purchases all of Four Corners’ coal requirements from NTEC, an entity owned by the Navajo Nation, under a coal supply contract (the “Four Corners CSA”) that expires in 2031. The coal comes from reserves located within the Navajo Nation. NTEC has contracted with Bisti Fuels Company, LLC, a subsidiary of The North American Coal Corporation, for management and operation of the mine. The contract provides for pricing adjustments over its term based on economic indices. See additional discussion of the Four Corners CSA in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Coal Mine Reclamation

As indicated under Coal Combustion Residuals Waste Disposal above, SJGS currently disposes of CCRs in the surface mine pits adjacent to the plant and Four Corners disposes of CCRs in ponds and dry storage areas. As discussed in Note 16 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, in conjunction with the shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA, the SJGS participants requested that the coal mine reclamation study for SJGS be updated periodically. The SJGS RA required PNM to complete an update to the reclamation cost estimate after the December 31, 2017 shutdown of SJGS Units 2 and 3. This reclamation cost estimate was completed in October 2018 and assumed continuation of mining operations through 2053. The 2018 study indicated a decrease in reclamation costs primarily driven by lower inflationary factors used to determine the estimated future cost of reclamation activities. PNM recorded its $2.5 million share of this decrease as of September 30, 2018 as regulatory disallowances and restructuring costs in the Condensed Consolidated Statements of Earnings.

As discussed above, on December 31, 2018, PNM submitted the December 2018 Compliance Filing to the NMPRC indicating that, consistent with the conclusions reached in PNM’s 2017 IRP (Note 12), PNM expects to retire its share of SJGS after the current SJGS CSA expires in mid-2022. PNM determined that recent events and circumstances regarding SJGS, including the December 2018 Compliance Filing, indicate that it is more likely than not that PNM’s share of SJGS will be retired in 2022. As a result, in December 2018 PNM again remeasured its liability for coal mine reclamation for the mine that serves SJGS to reflect that reclamation activities may occur beginning in 2022, rather than in 2053 as previously anticipated. This estimate resulted in an increase in overall reclamation costs due to an increase in the amount of fill dirt required to remediate the mine areas and

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(Unaudited)

the timing of activities necessary to reclaim the mine that serves SJGS. This remeasurement increased PNM’s liability for coal mine reclamation as of December 31, 2018 by $39.2 million, which reflects the increase in PNM’s obligation for both the underground and surface mines that serve SJGS. PNM recovers from retail customers reclamation costs associated with the underground mine. However, the NMPRC has capped the amount that can be collected from retail customers for final reclamation of the surface mines at $100.0 million. As a result, PNM recorded $9.4 million of the increase in the liability at December 31, 2018 related to the underground mine in regulatory assets on the Consolidated Balance Sheets and recorded the remaining $29.8 million associated with the surface mine as regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings. PNM’s estimate of the costs necessary to reclaim the mine that serves SJGS is subject to many assumptions, including the timing of reclamation, generally accepted practices at the time reclamation activities occur, and then current inflation and discount rates. In addition, PNM may be exposed to additional loss if the cost of reclamation activities are not approved by the NMPRC in connection with the NMPRC approvals indicated above.

The current estimate for decommissioning the mine serving Four Corners reflects the operation of the mine through 2031, the term of the Four Corners CSA.

Based on the 2018 estimates and PNM’s ownership share of SJGS, PNM’s remaining payments as of March 31, 2019 for mine reclamation, in future dollars, are estimated to be $102.6 million for the surface mines at both SJGS and Four Corners and $40.0 million for the underground mine at SJGS. At March 31, 2019 and December 31, 2018, liabilities, in current dollars, of $70.4 million and $70.1 million for surface mine reclamation and $23.8 million and $23.2 million for underground mine reclamation were recorded in other deferred credits.

Under the terms of the SJGS CSA, PNM and the other SJGS owners are obligated to compensate WSJ LLC 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 WSJ LLC for post-term reclamation obligations. As discussed in Note 16 of the Notes to the Consolidated Financial Statements on Form 10-K, as part of the restructuring of SJGS ownership the SJGS owners negotiated the terms of an amended agreement to fund post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable reclamation trust, and periodically deposit funds into the reclamation trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels. PNM funded $10.0 million in December 2018. Based on PNM’s reclamation trust fund balance at March 31, 2019, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $6.5 million in 2019, $10.2 million in 2020, and $10.9 million in 2021.

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 2018 and anticipates providing additional funding of $2.3 million in each of the years from 2019 through 2021.

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 impacts of changes in New Mexico state law as a result of the enactment of the ETA and regulatory determinations made by the NMPRC may also affect PNM’s financial position, results of operations, and cash flows. 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.

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(Unaudited)

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. 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 $14.1 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 $13.6 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 $41.6 million, with a maximum annual payment limitation of $6.2 million, to be adjusted periodically for inflation.

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.

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 2018 through 2021 has been endorsed by the parties and is being reviewed by the New Mexico Office of the 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,

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(Unaudited)

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 NM 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. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM entered its appearance in the appellate case and supported the settlement agreement in the NM District Court. On April 3, 2018, the New Mexico Court of Appeals issued an order affirming the decision of the NM District Court. Several parties filed motions requesting a rehearing with the New Mexico Court of Appeals seeking clarification of the order, which were denied. The State of New Mexico and various other appellants filed a Writ of Certiorari with the NM Supreme Court. The NM Supreme Court granted the State of New Mexico’s petition and denied the other parties’ requests. The issues regarding the Navajo Nation settlement have been briefed and are awaiting a decision by the NM Supreme Court. Adjudication of non-Indian water rights is ongoing.

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 matters 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 is proceeding in NM 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. Mediation was held on January 23, 2019. Discussions are continuing but the matter remains unresolved. 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.

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(Unaudited)

Navajo Nation Allottee Matters

In September 2012, 43 landowners filed a notice of appeal with the Bureau of Indian Affairs (“BIA”) appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The landowners 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 PNM is a rights-of-way grantee 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.  The allottees 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. The allottees filed a motion to dismiss their appeal with prejudice, which was granted in April 2014. 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. 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, which was denied. The NM District Court stayed the case 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. On April 30, 2018, the US Supreme Court declined to hear PNM’s Petition for Writ of Certiorari. The underlying litigation continues in the NM District Court. The NM District Court has not issued an updated scheduling order in the case due to the unresolved ownership of the fifth allotment. On March 27, 2019, several individual allottees filed a motion for partial summary judgment on the issue of trespass. Briefing is underway. PNM cannot predict the outcome of these matters.

(12) 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 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

PNM

New Mexico General Rate Cases

New Mexico 2015 General Rate Case (“NM 2015 Rate Case”)

On August 27, 2015, PNM filed an 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 application was based on a future test year (“FTY”) period beginning October 1, 2015 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 other economic factors. The 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. 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

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(Unaudited)

sales-leaseback transactions (Note 13). 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 CSA (Note 11).  PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current SJGS CSA, 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 13); 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 when the August 2016 RD was issued), but the customers would not bear any capital or depreciation costs other than those related to improvements made after the date of the original leases

• Disallowing recovery from retail customers of the rent expense, which aggregates $18.1 million per year, under the four leases of capacity in PVNGS Unit 1 that were extended for eight years beginning January 15, 2015 and the one lease of capacity in PVNGS Unit 2 that was extended for eight years beginning January 15, 2016 (Note 13) and related property taxes, which were $1.5 million per year when the August 2016 RD was issued; 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 11); 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. 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 for requiring 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 proposed retail customers receive 100% of the New Mexico jurisdictional portion of revenues from “refined coal” (a third-party pre-treatment process) at SJGS. 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

• Allowing 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

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. In addition, PNM’s statement indicated it is appealing the following specific elements of the NMPRC’s order:

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

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

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

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

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

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

• The NMPRC allowing PNM to recover the costs incurred under the new Four Corners CSA

• 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

The NM Supreme Court orally 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.

GAAP requires a loss 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. As of September 30, 2016, PNM estimated 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. 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 would not be recovered 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 has been recorded related to the issues subject to the cross-appeals.

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. As a result, PNM reevaluated the accounting consequences of the order in the NM 2015 Rate Case resulting in an additional pre-tax loss of $3.1 million, which represented seven months of capital cost recovery that the order disallowed and was not expected to be recovered through July 31, 2018.

During the second half of 2018, PNM updated its evaluation of the estimated time frame it would take for resolution of the matter resulting in additional pre-tax losses of $4.0 million, representing capital cost recovery that the order disallowed and that PNM estimated would not be recovered through April 30, 2019.

Since the NM Supreme Court did not issue a decision on the appeals by March 31, 2019, PNM again reevaluated the accounting consequences of the order in the NM 2015 Rate Case. As of March 31, 2019, PNM estimates the most likely period for the NM Supreme Court to issue a decision in the case and for the NMPRC to take any on any remanded issues is four months. As a result, PNM recorded an additional pre-tax loss of $1.3 million as of March 31, 2019, representing capital cost recovery that the order disallowed and will not be recovered through July 31, 2019. Further losses will be recorded if the currently estimated time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is 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 March 31, 2019, 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 $72.6 million, after considering the losses recorded to date

• 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 $37.6 million, after considering the losses recorded to date

• The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $49.7 million, after considering the losses recorded to date

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 $144.7 million (which amount includes $72.6 million that is the subject of PNM’s appeal discussed above) at March 31, 2019, after considering the losses recorded to date. 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. PNM’s original application used a FTY beginning January 1, 2018 and requested an increase in base non-fuel revenues of $99.2 million based on an ROE of 10.125%. The primary drivers of PNM’s revenue deficiency included implementation of modifications to PNM’s resource portfolio, which were approved by the NMPRC in December 2015 as part of the SJGS regional haze compliance plan, infrastructure investments, including environmental upgrades at Four Corners, declines in forecasted energy sales due to successful energy efficiency programs and other economic factors, and updates to FERC/retail jurisdictional allocations.

After extensive settlement negotiations and public proceedings, the NMPRC issued a Revised Order Partially Adopting Certification of Stipulation dated January 10, 2018 (the “Revised Order”). The key terms of the Revised Order include:

• An increase in base non-fuel revenues totaling $10.3 million, which includes a reduction to reflect the impact of the decrease in the federal corporate income tax rate and updates to PNM’s cost of debt (aggregating an estimated $47.6 million annually)

• A ROE of 9.575%

• Returning to customers over a three-year period the benefit of the reduction in the New Mexico corporate income tax rate (Note 14) to the extent attributable to PNM’s retail operations

• 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 then projected capital improvements during the period July 1, 2016 through December 31, 2018, but allowing recovery of the total $148.1 million of investments with a debt-only return

• An agreement to not implement non-fuel base rate changes, other than changes related to PNM’s rate riders, with an effective date prior to January 1, 2020

• A requirement to consider the prudency of PNM’s decision to continue its participation in Four Corners in a future proceeding

In accordance with the settlement agreement and the NMPRC’s final order, PNM implemented 50% of the approved increase for service rendered beginning February 1, 2018 and implemented the rest of the increase for service rendered beginning January 1, 2019.

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 and recovered. Initial comments were filed in July 2017 and several public workshops have been held. To date, no agreement has been reached. PNM cannot predict the outcome of this proceeding.

Renewable Portfolio Standard

Prior to the enactment of the ETA, the REA established 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. As discussed in Note 11, the ETA was signed into law on March 22, 2019. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also removes diversity requirements and certain customer caps and exemptions relating to the application of the RPS under the REA.

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(Unaudited)

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. The ETA sets a new threshold based on average annual levelized resource cost basis. 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 Riderbelow.

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

• 157 MW of PNM-owned solar-PV facilities, including 50 MW of PNM-owned solar-PV facilities approved by the NMPRC in PNM’s 2018 renewable energy procurement plan and are expected to be placed in commercial operation by the end of 2019

• 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, 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 15 MW

• Solar distributed generation, aggregating 106.8 MW at March 31, 2019, 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

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, and continuation of customer REC purchase programs and other purchases of RECs to ensure annual compliance with the RPS. 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. 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 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, which was denied. Briefing on NMIEC’s appeal of the fuel allocation methodology is complete. On June 20, 2018, NEE filed its Brief in Chief with the NM Supreme Court stating, among other things, that PNM’s process favored ownership of the 50 MW solar facilities compared to PPAs. PNM and the NMPRC each filed Answer Briefs on September 4, 2018 stating there is substantial evidence in the case record to support the NMPRC’s decision and that PNM’s RFP process was reasonable, complied with RPS requirements, and consistent with industry standards. NEE’s Reply Brief was filed on October 15, 2018. On May 6, 2019, the NM Supreme Court heard oral arguments on the issues of the fuel allocation methodology and the reasonableness of the RFP process. PNM cannot predict the outcome of this matter.

On June 1, 2018, PNM filed its 2019 renewable energy procurement plan. The plan meets RPS and diversity requirements for 2019 and 2020 using resources already approved by the NMPRC and did not propose any significant new procurements. PNM projects that the plan will be within the RCT in 2019 and will slightly exceed the current RCT in 2020. Public hearings were held on the case in September and October 2018. The NMPRC approved PNM’s 2019 renewable energy procurement plan on November 28, 2018.

As discussed above, the ETA removes certain customer caps and exemptions relating to the application of the RPS under the REA. As a result of these changes, PNM will be required to procure additional energy from renewable resources to meet the 20% by 2020 requirement under the RPS. PNM expects to request NMPRC approval of a PPA for wind generation capacity, which

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(Unaudited)

would utilize the BB2 Line to deliver the power, to meet this requirement. See additional discussion below under Application For a New 345 KV Transmission Line. 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. In its 2019 renewable energy procurement plan case, which was approved by the NMPRC on November 28, 2018, PNM proposed to collect $49.6 million for the year. The 2019 renewable energy procurement plan became effective on January 1, 2019. PNM recorded revenues from the rider of $12.7 million and $10.9 million in the three months ended March 31, 2019 and 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 did not exceed such limitation in 2018.

Energy Efficiency and Load Management

Petition for Energy Efficiency Disincentive

PNM’s application in the NM 2016 Rate Case had requested a “lost contribution to fixed cost” mechanism to address the disincentives associated with PNM’s energy efficiency programs. In the revised stipulation to that case, PNM agreed to withdraw its proposal for such a mechanism and to address energy efficiency disincentives in a future docket. On March 2, 2018, PNM filed a petition proposing a “lost contribution to fixed cost mechanism” with substantially the same terms as those proposed in the NM 2016 Rate Case application. The Hearing Examiner issued a procedural order that included a public hearing to begin on October 30, 2018. Subsequently, the Hearing Examiner extended the deadline to file response testimony until December 19, 2018 and vacated the hearing schedule. On December 19, 2018, the Hearing Examiner approved a joint motion filed by PNM and other parties in the case to hold the proceedings in abeyance until mid-March 2019. During the 2019 New Mexico legislative session, the EUEA was amended to, among other things, include a decoupling mechanism for disincentives, preclude a reduction to a utility’s ROE based on approval of disincentive or incentive mechanisms, and to establish savings targets for the period 2021 through 2025. On May 6, 2019, PNM submitted a request to the NMPRC to dismiss this matter and indicating that PNM will propose a mechanism to address disincentives in accordance with the amended EUEA in a future general rate case filing. PNM cannot predict the outcome of this matter.

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. 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 and because they asserted that the 2014 IRP did not conform to the NMPRC’s IRP rule. 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. On May 4, 2016, the NMPRC issued a 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.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2017 IRP

PNM filed its 2017 IRP on July 3, 2017. The 2017 IRP addresses the 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 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 Independent System Operator Western Energy Imbalance Market

• PNM should analyze its current Reeves 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. On January 16, 2018, the Hearing Examiner issued an order setting the scope of the proceedings as the 2017 IRP’s compliance with the applicable statute and NMPRC rules. Hearings were held in June 2018. On October 26, 2018, the Hearing Examiner issued a recommended decision recommending that the NMPRC accept PNM’s 2017 IRP as compliant with the applicable statute and NMPRC rules. On December 19, 2018, the NMPRC issued a final order accepting the Hearing Examiner’s recommended decision. On January 18, 2019, the Board of the County of Commissioners for San Juan County, New Mexico, the City of Farmington, New Mexico, and other parties filed a Notice of Appeal with the NM Supreme Court regarding the NMPRC’s final order in PNM’s 2017 IRP. The due date for Statements of Issues in the appeal has been extended to May 10, 2019 at the request of appellants in the case. On January 18, 2019, NEE submitted a motion requesting the NMPRC reconsider its acceptance of PNM’s 2017 IRP and alleging informational inadequacy and deficiencies in PNM’s filing. On January 29, 2019, PNM submitted a filing to the NMPRC in response to NEE’s motion for reconsideration. In its response, PNM stated that the issues raised by NEE had already been considered and rejected by the NMPRC in its December 19, 2018 final order and that the NMPRC lacks jurisdiction over the matters because the NMPRC’s final order has been appealed to the NM Supreme Court. The NMPRC did not take action on NEE’s motion for reconsideration. On February 19, 2019, NEE filed a motion with the NM Supreme Court to intervene in the appeal and to seek remand of the matter to the NMPRC. On March 11, 2019, PNM filed its response with the NM Supreme Court stating that the NMPRC has already considered and, by operation of law, denied NEE’s motion for reconsideration. PNM cannot predict the outcome of this matter.

The NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA required 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. PNM submitted its December 2018 Compliance Filing to the NMPRC on December 31, 2018 indicating that, consistent with the conclusions reached in the 2017 IRP, PNM’s customers would benefit from the retirement of PNM’s share of SJGS in 2022. The December 2018 Compliance Filing and the 2017 IRP are not a final determinations of PNM’s future generation portfolio. Retiring PNM’s share of SJGS capacity will require future NMPRC approval. PNM will also be required to obtain NMPRC approval of an exit from Four Corners, which PNM will seek at an appropriate time in the future. Likewise, NMPRC approval of new generation resources through CCNs, PPAs, or other applicable filings, would be required. The outcome of these future abandonment filings and the related impact on PNM’s generation portfolio will also be significantly influenced by the recent enactment of the ETA. See Note 11. PNM cannot predict the outcome of these matters.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Cost Recovery Related to Joining the EIM

The California Independent System Operator (“CAISO”) developed the Western Energy Imbalance Market (“EIM”) as a real-time wholesale energy trading market that enables participating electric utilities to buy and sell energy. The EIM aggregates the variability of electricity generation and load for multiple balancing authority areas and utility jurisdictions. In addition, the EIM facilitates greater integration of renewable resources through the aggregation of flexible resources by capturing diversity benefits from the expanded geographic footprint and the expanded potential uses for those resources.

In 2018, PNM completed a cost-benefit analysis of participating in the EIM. PNM’s analysis indicated participation in the EIM would provide substantial benefits to retail customers. On August 22, 2018, PNM filed an application with the NMPRC requesting, among other things, to recover an estimated $20.9 million of initial capital investments and authorization to establish a regulatory asset to recover an estimated $7.4 million of other expenses that would be incurred in order to join the EIM. PNM’s application proposed the regulatory asset be adjusted to provide for full recovery of such costs, including carrying charges, until the effective date of new rates in PNM’s next general rate case. PNM’s application also proposed the benefits of participating in the EIM be credited to retail customers through PNM’s existing FPPAC and that PNM would seek recovery of its costs in a future proceeding. A public hearing was held on December 12, 2018. On December 19, 2018, the NMPRC issued an order approving the establishment of a regulatory asset to recover PNM’s cost of joining the EIM. On January 17, 2019, ABCWUA filed a motion to reopen the case and to reconsider the NMPRC’s order approving the establishment of a regulatory asset. PNM submitted its response opposing reconsideration of the case on January 28, 2019. On February 6, 2019, the NMPRC issued an order granting rehearing and vacating the December 19, 2018 order. On February 27, 2019, the NMPRC issued a procedural order appointing a Hearing Examiner and requiring the Hearing Examiner to report to the NMPRC on whether the matter should be reopened. On March 18, 2019, the Hearing Examiner issued a recommended decision recommending approval of the establishment of a regulatory asset but deferring certain rate making issues, including but not limited to issues related to implementation and ongoing EIM costs and savings, the prudence and reasonableness of costs to be included in the regulatory asset, and the period over which costs would be charged to customers. PNM filed limited exceptions to the recommended decision related to the deferral of certain reasonableness findings. The NMPRC issued a final order adopting the Hearing Examiner’s recommended decision on March 27, 2019. On April 12, 2019, PNM and other parties filed a joint motion requesting the NMPRC clarify that the quarterly benefits reports prepared by CAISO be used to determine the benefits of participating in the EIM, as well as to support the prudence of costs incurred to join the EIM. On April 24, 2019, the NMPRC issued an order granting the joint motion for clarification and indicating the CAISO quarterly benefits reports may be used in a future rate case. PNM anticipates it will begin participating in the EIM in April 2021.

Facebook, Inc. Data Center Project

As discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, in 2016, the NMPRC approved a PNM application for arrangements in connection with services to be provided to Facebook, Inc. for a data center being constructed in PNM’s service area. 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. The cost of renewable energy procured is passed through to Facebook under a rate rider. A special service rate is applied to Facebook’s energy consumption in those hours of the month when their consumption exceeds the energy production from the renewable resources. In late 2017, PNM’s executed its initial procurement for the energy production from 30 MW of solar-PV capacity from NMRD, a 50% equity method of investee PNMR Development. Of this capacity, 10 MW began commercial operation in each of January 2018, March 2018, and May 2018.

PNM obtained NMPRC approval to enter into additional 25-year PPAs to purchase renewable energy and RECs to be used by PNM to supply renewable energy to Facebook. These PPAs include the purchase of the power and RECs from:

• Casa Mesa Wind, LLC, a subsidiary of NextEra Energy Resources, LLC, which is located near House, New Mexico, has a total capacity of 50 MW, and became operational in November 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

• Two PPAs to purchase renewable energy and RECs from an aggregate of approximately 100 MW of capacity from two solar-PV facilities to be owned and operated by NMRD. NMRD is required to obtain FERC approval of the PPAs. Subject

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

to FERC approval, the first 50 MW of these facilities is expected to begin commercial operation in December 2019 and the remaining capacity is expected to begin commercial operation in June 2020.

On March 15, 2019, PNM participated with NMRD in an application requesting FERC approval of the two PPAs aggregating approximately 100 MW of capacity. PNM cannot predict if the FERC will approve this filing.

Application For a New 345 KV Transmission Line

On August 10, 2018, PNM filed an application seeking NMPRC approval of a CCN to construct and operate a 345 KV transmission line and associated facilities (the “BB2 Line”), and to determine the rate making treatment to apply to the BB2 line and related rights-of-way. In the application, PNM states that the BB2 line would run adjacent to one of PNM’s existing transmission lines and is necessary to serve additional renewable generating resources to be located in eastern New Mexico. PNM’s use of the BB2 line would benefit all customers and would include delivery of approximately 166 MW of renewable energy and RECs under a PPA, which had previously been approved by the NMPRC, from La Joya Wind. The energy and RECs from the La Joya Wind PPA would be used to a serve the needs of a data center being constructed in PNM’s service territory and the capacity and energy from the PPA will also be used to meet the system needs of all PNM customers. See additional discussion in Facebook, Inc. Data Center Project above. PNM’s application requested that the NMPRC apply standard ratemaking treatment to the estimated $85 million cost of the project resulting in a jurisdictional allocation of costs to all of PNM’s transmission and retail customers. NMPRC staff supported PNM’s proposed ratemaking treatment of the BB2 project and indicated that the capacity and energy of the La Joya PPA and related network upgrades to PNM’s transmission system would benefit all of PNM’s customers. On March 11, 2019, the Hearing Examiner assigned to the application issued a recommended decision recommending approval of the CCN and related rights-of-way but recommending the NMPRC deny PNM’s request to allocate a portion of cost of the BB2 Line to retail customers. The Hearing Examiner’s recommendation indicated the costs not recovered from retail customers be directly reimbursed to PNM by Facebook, Inc. As a result, Facebook, Inc. would be responsible for approximately 46 percent, or $39.0 million, of the estimated cost of the project. On March 20, 2019, PNM filed exceptions to the recommended decision and requested oral argument. In its filing, PNM refuted the proposed finding that the BB2 Line is not part of PNM’s overall transmission system, opposed the recommendation that approximately 46 percent of the estimated cost of the project be directly assigned to Facebook, Inc. and presented legal arguments in support of PNM’s originally proposed ratemaking treatment. On April 16, 2019, the NMPRC issued an order approving the Hearing Examiner’s recommended decision, including the requirement that PNM be directly reimbursed by Facebook, Inc. In late April 2019, PNM and other parties submitted filings with the NMPRC requesting rehearing and seeking reconsideration of the NMPRC’s decision to deny standard ratemaking treatment of the cost of the BB2 Line and associated facilities. PNM cannot predict the outcome of this matter.

TNMP

TNMP 2018 Rate Case

On May 30, 2018, TNMP filed a general rate proceeding with the PUCT (the “TNMP 2018 Rate Case”) requesting an annual increase to base rates of $25.9 million based on a requested ROE of 10.5%, a cost of debt of 7.2%, and a capital structure comprised of 50% debt and 50% equity. TNMP’s application included a request to establish new rate riders to recover Hurricane Harvey restoration, rate case, and additional vegetation management costs. The application also included the integration of revenues previously recorded under the AMS rider and collection of other unrecovered AMS investments into base rates. In 2018, TNMP recorded revenues of $20.2 million under the AMS rider. The TNMP 2018 Rate Case application also proposed to return the regulatory liability recorded at December 31, 2017 related to federal tax reform to customers and to reduce the federal corporate income tax rate to 21%.

On December 20, 2018, the PUCT approved an unopposed settlement agreement in the case. The PUCT’s final order results in a $10.0 million annual increase to base rates. The key elements of the approved settlement include a ROE of 9.65%, a cost of debt of 6.44%, and a capital structure comprised of 55% debt and 45% equity. As stated by the settlement agreement, the PUCT’s final order excludes certain items from rate base that were requested in TNMP’s original filing, including approximately $10.6 million of transmission investments that TNMP included in its January 2019 transmission cost of service filing, which was approved by the PUCT in March 2019. In addition, the PUCT’s final order requires TNMP to refund approximately $37.8 million of the regulatory liability recorded at December 31, 2017 related to federal tax reform to customers over a period of five years and the remaining amount over the estimated useful lives of plant in service as of December 31, 2017; approves TNMP’s request to integrate revenues historically recorded under TNMP’s AMS rider, as well as other unrecovered AMS investments, into base rates;

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

approves TNMP’s request for new depreciation rates; and approves a new rider to recover Hurricane Harvey restoration costs, net of amounts to be refunded to customers resulting from the reduction in the federal income tax rate in 2018. See Note 14. The TNMP 2018 Rate Case also resulted in a reallocation of costs between TNMP’s transmission and retail customers and other rate design changes that reallocated costs between certain demand-based customers and customers billed on a volumetric basis. New rates under the TNMP 2018 Rate Case were effective beginning January 1, 2019.

Transmission Cost of Service Rates

TNMP can update its transmission cost of service (“TCOS”) rates twice per year to reflect changes in its invested capital although updates are not allowed while a general rate case is in process. 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)
September 8, 2016	$	9.5	$	1.8
March 14, 2017	30.2		4.8
September 13, 2017	27.5		4.7
March 27, 2018	32.0		0.6
March 21, 2019	111.8		14.3

Order Related to Changes in Federal Income Tax Rates

On January 25, 2018, the PUCT issued an accounting order that addresses the change in the federal corporate income tax rates on investor-owned utilities in the state of Texas. The order required 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 corporate income tax rate.

In addition, the order required 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 (Note 14). In compliance with the PUCT order, during the three months ended March 31, 2018, TNMP reduced revenues by $1.5 million to reflect the impact of the reduction in the federal corporate income tax rate beginning January 25, 2018. As discussed above, the total amount owed for the year ended 2018 of $5.4 million was offset against TNMP’s Hurricane Harvey restoration costs as of December 31, 2018 and is being refunded to customers as a component of a new rate rider over a period of no more than five years beginning on January 1, 2019.

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 and over collected costs from prior years, rate case expenses, and performance bonuses (if programs exceed mandated savings goals). On May 30, 2018, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2019. The total amount requested was $5.7 million, which included a performance bonus of $0.9 million based on TNMP’s energy efficiency achievements in the 2017 plan year. On June 21, 2018, the PUCT issued a declaratory order announcing the PUCT’s interpretation of the bonus calculation in its rule. The order does not affect cost recovery but reduces the bonus calculation as filed by utilities in their current EECRF proceedings. Accordingly, in June of 2018, TNMP reduced its estimated performance bonus for the 2017 plan year to $0.8 million. On August 6, 2018, TNMP and other parties to the case reached a unanimous settlement stipulation to provide $5.6 million of EECRF recovery, which includes a performance bonus of $0.8 million. On October 12, 2018, the PUCT approved the settlement stipulation with rates to become effective on March 1, 2019.

(13) Lease Commitments

The Company enters into various lease agreements to meet its business needs and to satisfy the needs of its customers. Historically, the Company’s leases were classified as operating leases which included leases for generating capacity from PVNGS Units 1 and 2, certain rights-of-way agreements for transmission lines and facilities, vehicle and equipment leases necessary to

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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 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

construct and maintain the Company’s assets and building and office equipment leases. In February 2016, the FASB issued ASU 2016-02 - Leases (Topic 842) to provide guidance on the recognition, measurement, presentation, and disclosure of leases. Among other things, ASU 2016-02 requires that all leases be recorded on the balance sheets by recognizing a present value liability for future cash flows of the lease agreement and a corresponding right-of-use asset. The Company adopted Topic 842 on January 1, 2019, its required effective date. The Company elected to use many of the practical expedients available upon adoption of the standard. As a result, the Company will continue to classify its leases existing as of December 31, 2018 as operating leases until they expire or are modified. In addition, the Company elected the practical expedient to not reevaluate the accounting for land easements and rights-of-way agreements existing at December 31, 2018. The Company also elected the use of the practical expedient to apply the requirements of the new standard on its effective date and has not restated prior periods to conform to the new guidance. Adoption of the lease standard has a material impact on the Company’s Condensed Consolidated Balance Sheets but does not have a material impact on the Condensed Consolidated Statements of Earnings or the Condensed Consolidated Statements of Cash Flows.

Effective January 1, 2019, the Company accounts for contracts that convey the use and control of identified assets for a period of time as leases. The Company classifies leases as operating or financing by evaluating the terms of the lease agreement. Agreements under which the Company is likely to utilize substantially all of the economic value or life of the asset or which the Company is likely to own at the end of the lease term, either through purchase or transfer of ownership, are classified as financing leases. Leases not meeting these criteria are accounted for as operating leases. Agreements under which the Company is a lessor are insignificant. Leases with terms that are expected to exceed one year are recognized on the Company’s Condensed Consolidated Balance sheet by recording a lease liability and corresponding right-of-use asset. PNMR, PNM, and TNMP determine present value for their leases using their incremental borrowing rates at the commencement date of the lease or, when readily available, the rate implicit in the agreement. However, in most cases the implicit interest rate is not available in the Company’s lease agreements. Operating lease expense is recognized within operating expenses according to the use of the asset on a straight-line basis. Financing lease costs are recognized by amortizing the right-of-use asset on a straight-line basis and by recording interest expense on the lease liability. Financing lease right-of-use assets amortization is reflected in depreciation and amortization and interest on financing lease liabilities is reflected as interest charges on the Company’s Condensed Consolidated Statements of Earnings.

PVNGS

PNM leases interests in Units 1 and 2 of PVNGS. 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. Following procedures set forth in the PVNGS leases, PNM notified four of the lessors under the Unit 1 leases and one lessor under the Unit 2 lease that it would elect to renew those leases on the expiration date of the original leases. 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 lease payments during the renewal periods aggregate $16.5 million for PVNGS Unit 1 and $1.6 million for Unit 2.

The terms of each of the extended leases do not provide for additional renewal options beyond their currently scheduled expiration dates. PNM has the option to purchase the assets underlying each of the extended leases at their fair market value or to return the lease interests to the lessors on the expiration dates. Under the terms of the extended leases, PNM has until January 15, 2020 for the Unit 1 leases and January 15, 2021 for the Unit 2 lease to provide notices to the lessors of PNM’s intent to exercise the purchase options or to return the leased assets to the lessors. PNM’s elections are independent for each lease and are irrevocable. In the proceeding addressing PNM’s 2017 IRP (Note 12), PNM agreed to promptly notify the NMPRC of a decision to extend the Unit 1 or 2 leases, or to exercise its option to purchase the leased assets at fair market value upon the expiration of leases. If PNM elects to exercise its purchase option under any of the leases, the leases provide an appraisal process to determine fair market value. If PNM elects to return the assets underlying the extended leases, PNM will retain certain obligations related to PNVGS, including costs to decommission the facility. PNM would seek to recover its undepreciated investments at the end of the PVNGS leases as well as any future obligations related to PNM’s leased capacity from NM retail customers. Any transfer of the assets underlying the leases will be required to comply with NRC licensing requirements.

On April 22, 2019, NEE and other parties, which consist primarily of environmental not-for-profit organizations, filed a joint petition for expedited investigation with the NMPRC. The joint petition requests the NMPRC open an investigation regarding PNM’s option to purchase the assets underlying the PVNGS Unit 1 and 2 leases that will expire in January 2023 and 2024. PNM cannot predict the outcome of this matter.

PNM elected to purchase the assets underlying the other three PVNGS Unit 2 leases at the end of their original lease terms. PNM and the lessors under those leases entered into agreements that established the purchase price, representing the fair market value, to be paid by PNM. On January 15, 2016, PNM paid $78.1 million to the lessor under one lease for 31.25 MW of the

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case, including PNM’s pending appeal to the NM Supreme Court of certain matters in the 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 lessors, and take title to the leased interests. If such an event had occurred as of March 31, 2019, amounts due to the lessors under the circumstances described above would be up to $161.2 million, payable on July 15, 2019 in addition to the scheduled lease payments due on July 15, 2019. In such event, PNM would record the acquired assets at the lower of their fair value or the amount paid.

Land Easements and Rights-of-Ways

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. 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. PNM’s April 2018 payment for the amount due under the Navajo Nation right-of-way lease was $6.9 million, which included amounts due under the Consumer Price Index adjustment, and was used to determine PNM’s operating lease liability as of January 1, 2019 and is included in the table of future lease payments shown below. Changes in the Consumer Price Index subsequent to January 1, 2019 are considered variable lease payments.

Fleet Vehicles and Equipment

As of December 31, 2018, all of the Company’s leases of fleet vehicles and equipment are classified as operating leases. Historically, the Company has utilized substantially all of the economic value of its fleet and equipment leases by the end of the lease term. The Company generally has the contractual ability to return its fleet vehicle and equipment leases to the lessor after one-year provided the lessor can recover remaining amounts owed under the agreement from third-parties or through make-whole provisions in the contract but does not typically exercise this right. As a result, fleet vehicle and equipment leases commencing on or after January 1, 2019 are classified as financing leases. The Company’s fleet vehicle and equipment lease agreements include non-lease components for insignificant administrative and other costs that are billed over the life of the agreement. The Company has elected to combine these fees with the lease components of the agreement. Certain of the Company’s fleet vehicle and equipment leases contain residual value guarantees. At March 31, 2019, residual value guarantees on fleet vehicle and equipment leases are $0.5 million, $1.1 million, and $1.6 million for PNM, TNMP, and PNMR.

Other

The Company holds a number of office space and office equipment leases. The Company’s current office space leases, all of which existed as of December 31, 2018, are classified as operating leases. These agreements include non-lease components for costs such as common area maintenance fees, which the Company has elected to combine with the lease component of the agreements. Certain of the Company’s office space leases are held between the Company’s consolidated subsidiaries and have been eliminated on consolidation. See Note 15. The Company’s office equipment leases are primarily for copiers and other graphics equipment. The Company classifies its office equipment leases existing as of December 31, 2018 as operating leases. Office equipment leases commencing on or after January 1, 2019 are classified as financing leases.

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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 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below:

	March 31, 2019						January 1, 2019
	PNM		TNMP		PNMR Consolidated		PNM		TNMP		PNMR Consolidated
	(In thousands)
Operating leases:
Operating lease assets, net of amortization	$	137,756	$	12,160	$	150,426	$	143,816	$	12,942	$	157,440
Current portion of operating lease liabilities	22,762		3,023		26,197		21,589		3,132		25,189
Long-term portion of operating lease liabilities	115,436		9,088		124,937		124,891		9,787		135,174

As discussed above, the Company classifies its fleet vehicle and equipment leases and its office equipment leases commencing on or after January 1, 2019 as financing leases. Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below:

	March 31, 2019
	PNM			TNMP			PNMR Consolidated
	(In thousands)
Financing leases:
Non-utility property	$	1,635		$	1,268		$	2,904
Accumulated depreciation	(37		)	(40		)	(78		)
Non-utility property, net	$	1,598		$	1,228		$	2,826
Other current liabilities	$	233		$	217		$	450
Other deferred credits	1,083			1,006			2,089

Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below:

	March 31, 2019
	PNM		TNMP		PNMR Consolidated
Weighted average remaining lease term (In years):
Operating leases	7.18		4.67		6.95
Financing leases	5.72		5.75		5.74
Weighted average discount rate:
Operating leases	3.88	%	3.88	%	3.88	%
Financing leases	4.34	%	4.55	%	4.43	%

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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 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Information for the components of lease expense is as follows:

	Three Months Ended March 31, 2019
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Total operating lease expense	$	7,231	$	241	$	7,611
Financing lease expense:
Amortization of right-of-use assets	66		58		125
Interest on lease liabilities	16		17		32
Total financing lease expense	82		75		157
Variable lease expense	—		—		—
Short-term lease expense	74		3		94
Total lease expense for the period	$	7,387	$	319	$	7,862

Supplemental cash flow information related to the Company’s leases is as follows:

	Three Months Ending March 31, 2019
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	9,452	$	284	$	9,891
Operating cash flows from financing leases	16		17		32
Finance cash flows from financing leases	25		33		58
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	143,816	$	12,942	$	157,440
Financing leases	1,635		1,268		2,904

Excluded from the lease expense and cash flow information tables above are $0.4 million, $0.7 million, and $1.1 million of capitalized operating lease costs, and less than $0.1 million of capitalized financing lease costs at PNM, TNMP, and PNMR. These capitalized costs are reflected as investing activities on the Company’s Condensed Consolidated Statements of Cash Flows.

Future expected lease payments as of March 31, 2019 and December 31, 2018 are shown below:

	As of March 31, 2019
	PNM				TNMP				PNMR Consolidated
	Financing		Operating		Financing		Operating		Financing		Operating
	(In thousands)
Remainder of 2019	$	266	$	17,917	$	209	$	2,622	$	475	$	20,980
2020	344		27,045		269		2,993		613		30,555
2021	332		26,505		259		2,398		591		29,158
2022	319		26,235		249		1,846		568		28,255
2023	307		17,457		181		1,281		488		18,879
Later years	224		42,328		214		1,151		438		43,490
Total minimum lease payments	1,792		157,487		1,381		12,291		3,173		171,317
Less: Imputed interest	476		19,289		158		180		634		20,183
Lease liabilities as of March 31, 2019	$	1,316	$	138,198	$	1,223	$	12,111	$	2,539	$	151,134

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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 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	As of December 31, 2018
	Operating leases
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Remainder of 2019	$	27,691	$	3,664	$	31,772
2020	27,000		3,102		30,404
2021	26,462		2,324		29,012
2022	26,217		1,795		28,175
2023	17,447		1,279		18,868
Later years	42,329		1,150		43,489
Total minimum lease payments	167,146		13,314		181,720

The above tables include $9.9 million, $12.2 million, and $22.1 million for PNM, TNMP, and PNMR at March 31, 2019 and $7.5 million, $11.0 million, and $18.5 million for PNM, TNMP, and PNMR at December 31, 2018 for expected future payments on fleet vehicle and equipment leases that could be avoided if the leases were returned and the lessor is able to recover estimated market value for the equipment from third parties. The Company’s contractual commitments for leases that have not yet commenced are insignificant.

(14) Income Taxes

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 made 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 eliminated federal bonus depreciation for utilities, limited interest deductibility for non-utility businesses and limited the deductibility of officer compensation. During 2018, the IRS issued additional guidance related to certain officer compensation, as well as proposed regulations on interest deductibility that provide a 10% “de minimis” exception that allows entities with predominantly regulated activities to fully deduct interest expenses. In addition, the IRS issued proposed regulations interpreting Tax Act amendments to depreciation provisions of the Internal Revenue Code that allow the Company to claim a bonus depreciation deduction on certain construction projects placed in service subsequent to the third quarter of 2017. See additional discussion of the impacts of the Tax Act in Note 18 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Beginning February 2018, PNM’s NM 2016 Rate Case reflects the reduction in the federal corporate income rate, including amortization of excess deferred federal income taxes that are being returned to customers over a twenty-one year period; and reductions in the New Mexico corporate tax rate, including amortization of excess deferred state income taxes that are being returned to customers over a three-year period. On January 25, 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. During the three months ended March 31, 2018, TNMP reduced revenue and recorded a regulatory liability of $1.5 million in accordance with the PUCT’s order. The approved settlement in the TNMP 2018 Rate Case includes a reduction in customer rates to reflect the impacts of the Tax Act beginning on January 1, 2019. See additional discussion of PNM’s NM 2016 Rate Case and TNMP’s 2018 Rate Case in Note 12.

As required under GAAP, 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 income taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, including excess tax benefits related to stock awards, be excluded from the estimated annual effective tax rate calculation. At March 31, 2019, PNMR, PNM, and TNMP estimated their effective income tax rates for the year ended December 31, 2019 would be 9.42%, 11.89%, and 8.41%. The primary permanent difference is the reduction in income tax expense resulting from the amortization of excess deferred federal and state income taxes ordered by the NMPRC in PNM’s NM 2016 Rate Case and the amortization of excess deferred federal income taxes as ordered by the PUCT in TNMP’s 2018 Rate Case. During the three months ended March 31, 2019, income tax expense calculated by applying the expected annual effective income tax rate to earnings before income taxes was further reduced

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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 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

by excess tax benefits related to stock awards of $0.7 million for PNMR, of which $0.5 million was allocated to PNM and $0.2 million was allocated to TNMP.

(15) Related Party Transactions

PNMR, PNM, TNMP, and NMRD 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. In addition, PNMR provides construction and operations and maintenance services to NMRD, a 50% owned subsidiary of PNMR Development (Note 1), and PNM purchases renewable energy from certain NMRD-owned facilities at a fixed price per MWh of energy produced. PNM also provides interconnection services to PNMR Development (Note 9) and NMRD.

The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD:

	Three Months Ended
	March 31,
	2019		2018
	(In thousands)
Services billings:
PNMR to PNM	$	26,826	$	23,679
PNMR to TNMP	10,058		8,365
PNM to TNMP	75		86
TNMP to PNMR	35		35
PNMR to NMRD	41		78
Renewable energy purchases:
PNM from NMRD	625		370
Interconnection billings:
PNM to NMRD	—		—
PNM to PNMR	—		—
Interest billings:
PNMR to PNM	933		62
PNM to PNMR	72		66
PNMR to TNMP	32		8
Income tax sharing payments:
PNMR to PNM	—		—
TNMP to PNMR	—		—

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ITEM 2. 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-Q General Instruction H(2). This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. A reference to a “Note” in this Item 2 refers to the accompanying Notes to Condensed Consolidated Financial Statements (Unaudited) included in Item 1, 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 784,000 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 at or 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 business operations, including transitioning to an emissions-free generating portfolio by 2040

• 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.

Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 12.

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

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(“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.

The NMPRC’s September 28, 2016 order included a 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 equipment on SJGS Units 1 and 4. 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 13) 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 13)

• 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; 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

On September 30, 2016, PNM filed a notice of appeal with the NM Supreme Court regarding the order in the NM 2015 Rate Case. 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. PNM’s appeal includes the following specific 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

The NM Supreme Court has orally stated that the court’s intent would be to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits. 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.

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 September 30, 2016 for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. Accordingly, PNM recorded pre-tax regulatory disallowances of $11.3 million representing capital cost recovery for the period October 1, 2016 through December 31, 2017 on its investments that the order disallowed, as well as

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amounts recorded as regulatory assets and deferred charges that the order disallowed, and which PNM did not challenge in its appeal. PNM has periodically updated its estimate of the time frame necessary to resolve these matters resulting in additional pre-tax disallowances of $3.1 million and $4.0 million being recorded in December 2017 and in the second half of 2018. Since the NM Supreme Court did not issue a decision by March 31, 2019, PNM again reevaluated its estimate of the time frame necessary to resolve the matter. As of March 31, 2019, PNM recorded additional pre-tax disallowances of $1.3 million representing additional cost recovery the order disallowed and will not be recovered from customers. PNM’s aggregate pre-tax losses of $19.7 million assumes the NM Supreme Court will issue a decision and that any remanded issues will be addressed by the NMPRC by July 31, 2019. Additional losses will be recorded if the currently 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 March 31, 2019 book values of PNM’s investments that the order disallowed, after considering the losses recorded to date, were $72.6 million for the 64.1 MW of purchased capacity in PVNGS Unit 2, $37.6 million for the PVNGS Unit 2 disallowed capital improvements, and $49.7 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 $144.7 million at March 31, 2019 (which includes $72.6 million that is the subject of PNM’s appeal discussed above) after considering the losses recorded to date. 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 January 16, 2018, the NMPRC issued an order that authorized PNM to implement an increase in base non-fuel rates of $10.3 million. PNM implemented 50% of the approved increase for service rendered, rather than bills sent, beginning February 1, 2018 and implemented the rest of the increase for service rendered beginning January 1, 2019. This order was on PNM’s application for a general increase in retail electric rates (the “NM 2016 Rate Case”) filed in December 2016. PNM’s December 2016 application requested an increase in base non-fuel revenues of $99.2 million based on a FTY beginning January 1, 2018 and an ROE of 10.125%. PNM’s December 2016 application did not include a request to recover any of the costs disallowed in the NM 2015 Rate Case that are at issue in PNM’s pending appeal to the NM Supreme Court. The primary drivers of PNM’s revenue deficiency included implementation of modifications to PNM’s resource portfolio, which were approved by the NMPRC in December 2015 as part of the SJGS regional haze compliance plan, infrastructure investments, including environmental upgrades at Four Corners, declines in forecasted energy sales due to successful energy efficiency programs and other economic factors, and updates to FERC/retail jurisdictional allocations.

After extensive settlement negotiations and public proceedings, the NMPRC issued a Revised Order Partially Adopting Certification of Stipulation dated January 10, 2018 (the “Revised Order”). The key terms of the Revised Order include:

• A revenue increase totaling $10.3 million, which includes a reduction to reflect the impact of the decrease in the federal corporate income tax rate and updates to PNM’s cost of debt (aggregating an estimated $47.6 million annually)

• A ROE of 9.575%

• Returning to customers over a three-year period the benefit of the reduction in the New Mexico corporate income tax rate (Note 14) to the extent attributable to PNM’s retail operations

• 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 allowing recovery of the total $148.1 million of investments with a debt-only return

• An agreement to not implement non-fuel base rate changes, other than changes related to PNM’s rate riders, with an effective date prior to January 1, 2020

• A decision to defer future consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to a future proceeding

PNM implemented 50% of the approved increase for service rendered beginning February 1, 2018 and implemented the rest of the increase for service rendered beginning January 1, 2019.

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TNMP 2018 Rate Case – On December 20, 2018, the PUCT approved a settlement stipulation allowing TNMP to increase annual base rates by $10.0 million based on a ROE of 9.65%, a cost of debt of 6.44%, and a capital structure comprised of 55% debt and 45% equity. Under the approved settlement stipulation TNMP was granted authority to integrate revenues previously recorded under the AMS rider, as well as other unrecorded AMS costs, into base rates; establish a new rider to recover Hurricane Harvey restoration costs, net of amounts owed to customers as a result of the reduction in the federal corporate income tax rate in 2018; and to update depreciation rates. In addition, the approved settlement stipulation allows TNMP to refund the regulatory liability recorded at December 31, 2017 related to federal tax reform to customers and reflects the reduction in the federal corporate income tax rate to 21%. New rates under the TNMP 2018 Rate Case became effective January 1, 2019.

TNMP’s original application, which was filed with the PUCT on May 30, 2018 (the “TNMP 2018 Rate Case”), requested an annual increase to base rates of $25.9 million based on a ROE of 10.5%, a cost of debt of 7.2%, and a capital structure comprised of 50% debt and 50% equity.

Advanced Metering –TNMP completed its mass deployment of advanced meters across its service territory in 2016 and has installed more than 242,000 advanced meters. As discussed above, beginning in 2019 the costs associated with TNMP’s AMS program are being recovered through base rates.

In February 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”), which was denied. As ordered by the NMPRC, PNM’s next energy efficiency plan filing will include a proposal for an AMI pilot project.

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 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.

Cost Recovery Related to Joining the EIM – In 2018, PNM completed a cost-benefit analysis that indicated PNM’s participation in the California Independent System Operator (“CAISO”) Western Energy Imbalance Market (“EIM”) would provide substantial benefits to retail customers. In August 2018, PNM filed an application with the NMPRC requesting, among other things, to recover the cost of initial capital investments and authorization to establish a regulatory asset to recover other expenses that would be incurred in order to join the EIM. PNM’s application proposes recovery of the costs incurred to join the EIM would be recovered beginning on the effective date of new rates in PNM’s next general rate case and that the benefits of participating in the EIM be credited to retail customers through PNM’s existing FPPAC. A public hearing was held on December 12, 2018. On December 19, 2018, the NMPRC issued an order approving the establishment of a regulatory asset to recover PNM’s cost of joining the EIM. On January 17, 2019, ABCWUA filed a motion to reopen the case and to reconsider the NMPRC’s order approving the establishment of a regulatory asset. On February 6, 2019, the NMPRC issued an order granting rehearing and vacating the December 19, 2018 order. On February 24, 2019, Western Resource Advocates, and the Coalition for Clean and Affordable Energy filed a motion for an expedited final order, which was supported by PNM and other parties and opposed by ABCWUA.  On February 27, 2019, the NMPRC issued a procedural order requiring the Hearing Examiner to report to the NMPRC whether the matter should be reopened. On March 18, 2019, the Hearing Examiner recommended that all rate making issues, including but not limited to implementation and ongoing EIM costs and savings, the prudence and reasonableness of costs included in a regulatory asset, and the period over which costs would be charged to customers be deferred until a future case. PNM filed limited exceptions to the recommended decision. The NMPRC issued a final order adopting the Hearing Examiner’s recommended decision on March 27, 2019. On April 12, 2019, PNM and other parties filed a joint motion requesting the NMPRC clarify that the quarterly benefits reports prepared by CAISO be used to determine the benefits of participating in the EIM, as well as to support the prudence of costs incurred to join the EIM. On April 24, 2019, the NMPRC issued an order granting the joint motion for clarification and indicating the CAISO quarterly benefits reports may be used in a future rate case. PNM anticipates it will begin participating in the EIM in April 2021.

FERC Regulation

Rates PNM charges wholesale transmission customers and wholesale generation customers are subject to traditional rate regulation by FERC. 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 transmission capital projects to be placed into service in the following year. The projections included are subject to true-up. Certain items, including changes to return on equity

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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 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.  Consequently, PNM decided to stop pursuing wholesale generation contracts and currently has no full-requirements wholesale generation customers.

Delivering At or Above Industry-Average Earnings and Dividend Growth

PNMR’s strategic goal to deliver at or 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 5% to 6% earnings and dividend growth for the period 2019 through 2022. 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 in the 50% to 60% range of its ongoing earnings. PNMR expects to provide at or 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
December 2015	10	%
December 2016	10	%
December 2017	9	%
December 2018	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 January 2018, S&P changed the outlook for PNMR, PNM, and TNMP from stable to negative. In June 2018, Moody’s changed the outlook for PNMR and PNM from positive to stable and maintained a stable outlook for TNMP.

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.

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Utility Plant and Strategic Investments

Utility Plant Investments – During the 2016 to 2018 period, PNM and TNMP together invested $1,501.7 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. PNM completed installation of SNCR and BDT equipment on SJGS Units 1 and 4 in early 2016. 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. During 2018 and 2019, PNM will construct an additional 50 MW of PNM-owned PV facilities, which were approved by the NMPRC in PNM’s 2018 renewable energy procurement plan. The 50 MW PV facilities are expected to be placed in commercial operations by December 2019 at a cost not to exceed $73.0 million. In late 2018, PNM became the first utility to install a new type of protective relay on its high-voltage transmission lines, which help to ensure the reliability of PNM’s electrical system. On May 1, 2019, PNM executed an agreement to purchase a 165-mile 345 kV transmission line and to construct associated facilities (the “Western Spirit Line”), subject to NMPRC and FERC approval. PNM anticipates the Western Spirit line will be used to serve approximately 800 MW of new wind generation facilities in eastern New Mexico beginning in 2021. See the subheading Capital Requirements included in the full discussion of Liquidity and Capital Resources below for additional discussion of the Company’s projected capital requirements.

Strategic Investments – In 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. 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 regulated jurisdictions. NMRD’s current renewable energy capacity in operation is 33.9 MW, which includes 30 MW of solar-PV facilities required to supply energy to the Facebook data center located within PNM’s service territory, 1.9 MW to supply energy to Columbus Electric Cooperative located in southwest New Mexico, and 2.0 MW to supply energy to the Central New Mexico Electric Cooperative. In August 2018, the NMPRC approved PNM’s request to enter into two additional 25-year PPAs to purchase renewable energy and RECs from an aggregate of approximately 100 MW of capacity from two solar-PV facilities to be constructed by NMRD to supply power to Facebook. NMRD is required to obtain FERC approval of the PPAs. Subject to FERC approval, these facilities are expected to be in commercial operation by June 2020.See Note 12. NMRD actively explores opportunities for additional renewable projects, including large-scale projects to serve future data centers 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 2017 IRP on July 3, 2017. 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

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• PNM should assess the costs and benefits of participating in the California Independent System Operator Western Energy Imbalance Market

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

On October 26, 2018, the Hearing Examiner issued a recommended decision recommending that the NMPRC accept PNM’s 2017 IRP as compliant with the applicable statute and NMPRC rules. On December 19, 2018, the NMPRC issued a final order accepting the Hearing Examiner’s recommended decision. On January 18, 2019, The Board of the County of Commissioners for San Juan County, New Mexico, the City of Farmington, New Mexico, and other parties filed a Notice of Appeal with the NM Supreme Court regarding the NMPRC’s final order in PNM’s 2017 IRP. The due date for Statements of Issues in the appeal has been extended to May 10, 2019 at the request of appellants in the case. On January 18, 2019, NEE submitted a motion requesting the NMPRC reconsider its acceptance of PNM’s 2017 IRP filing alleging informational inadequacy and deficiencies in PNM’s filing. On January 29, 2019, PNM submitted a filing to the NMPRC in response to NEE’s motion for reconsideration. In its response, PNM stated that the issues raised by NEE had already been considered and rejected by the NMPRC in its December 19, 2018 final order and that the NMPRC lacks jurisdiction over the matters because the NMPRC’s final order has been appealed to the NM Supreme Court. The NMPRC did not take action on NEE’s motion for reconsideration. On February 19, 2019, NEE filed a motion with the NM Supreme Court to intervene in the appeal and to seek remand of the matter to the NMPRC. On March 11, 2019, PNM filed its response to the NM Supreme Court stating that the NMPRC had already considered and, by operation of law, denied NEE’s motion for reconsideration. PNM cannot predict the outcome of this matter.

See additional discussion of PNM’s 2017 IRP and PNM’s December 2018 Compliance Filing regarding SJGS below and in Notes 11 and 12.

Environmentally Responsible Power

PNMR has a long-standing record of environmental stewardship. PNM’s environmental focus is in three key areas:

• Developing strategies to provide reliable and affordable power while transitioning to a 100% emissions-free generating portfolio by 2040

• Preparing PNM’s system 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 would further PNM’s goal to achieve a 100% emissions-free generating portfolio by 2040.

The Energy Transition Act (“ETA”)

On March 22, 2019, Senate Bill 489, known as the ETA, was signed into New Mexico state law and becomes effective on June 14, 2019. Prior to the enactment of the ETA, the REA established a mandatory RPS requiring utilities to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also amends sections of the REA to allow for the recovery of undepreciated investments and decommissioning costs related to qualifying EGUs that the NMPRC has required be removed from retail jurisdictional rates, provided replacement resources to be included in retail rates have lower or zero-carbon emissions. The ETA provides for a transition from fossil-fueled generating resources to renewable and other carbon-free resources by allowing utilities to issue securitized bonds, or “energy transition bonds,” related to the retirement of certain coal-fired generating facilities to qualified investors. Proceeds from the energy transition bonds must be used for purposes related to providing utility service to customers and to pay “financing costs” (as defined by the ETA). These costs may include coal mine decommissioning, plant decommissioning, and other costs that have not yet been charged to customers. Proceeds from energy transition bonds may also be used to fund severances for employees of the retired facility and related coal mine, and to promote economic development, education and job training in areas impacted by the retirement of the coal-fired facilities. The ETA requires the NMPRC to prioritize replacement resources in a manner intended to mitigate the economic impact to communities affected by these plant retirements. See additional discussion of the ETA in Note 11.

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The ETA will have a significant impact on PNM’s future generation portfolio, including PNM’s planned retirement of SJGS in 2022. PNM cannot predict the full impact of the ETA or the outcome of its potential future generating resource abandonment and replacement filings with the NMPRC.

SJGS

December 2018 Compliance Filing –As discussed in Note 16 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, the NMPRC’s December 2015 approval for a plan to comply with the EPA’s regional haze rule at SJGS required PNM to make a filing setting forth PNM’s recommendation, along with supporting testimony and exhibits, to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after June 30, 2022 (the “December 2018 Compliance Filing”). The December 2018 Compliance Filing was required to be made before PNM entered into a binding commitment for post-2022 coal supply, but after PNM had received firm pricing and other terms for the supply of coal, unless PNM did not intend to pursue an agreement for post-2022 coal supply at SJGS.

PNM submitted the December 2018 Compliance Filing to the NMPRC on December 31, 2018 indicating that, consistent with the conclusions reached in PNM’s 2017 IRP, PNM’s customers would benefit from the retirement of PNM’s share of SJGS (subject to future NMPRC approval) after the current SJGS CSA expires in mid-2022. The December 2018 Compliance Filing also indicates that all of the SJGS owners except for Farmington have provided written notice that they do not intend to extend the SJGS operating agreements beyond their June 30, 2022 expiration dates and that PNM has provided written notice that PNM does not intend to extend the SJGS CSA beyond June 30, 2022. The December 2018 Compliance Filing also requested the NMPRC’s December 2015 order remain closed, and that PNM anticipates it will have sufficient information by the end of the second quarter of 2019 to support a consolidated application seeking NMPRC approval to retire PNM’s share of SJGS in 2022 and for approval of CCNs, PPAs, or other applicable approvals, for resources to replace PNM’s capacity in SJGS. On January 30, 2019, the NMPRC approved an order initiating a proceeding and requiring PNM to submit an application for the abandonment of PNM’s share of SJGS in 2022 by March 1, 2019. On February 7, 2019, PNM filed a motion requesting the NMPRC vacate the January 30, 2019 order and extend the deadline for PNM’s abandonment filing until the end of the second quarter of 2019, which was deemed denied. On February 27, 2019, PNM filed a petition with the NM Supreme Court stating that the requirements of the January 30, 2019 order exceeded the NMPRC’s authority by, among other things, mandating PNM to make a filing that is legally voluntary, and that the order is contrary to NMPRC precedent which requires abandonment applications to also include identified replacement resources and other information that would not be available to PNM by March 1, 2019. PNM’s petition also requested the NM Supreme Court stay the January 30, 2019 order until after June 14, 2019. On March 1, 2019, the NM Supreme Court granted a temporary stay of the NMPRC’s order to consider the merits of PNM’s petition after receiving responses.  The NMPRC and NEE filed responses supporting the NMPRC’s authority to order PNM to initiate a proceeding. Other parties to the case filed responses supporting a stay of the NMPRC’s order and indicating that the abandonment filing should be subject to recently enacted changes in New Mexico state law. See additional discussion of the ETA above, and PNM’s December 2018 Compliance Filing in Note 11. PNM cannot predict the outcome of this matter.

The December 2018 Compliance Filing and the 2017 IRP are not final determinations of PNM’s future generation portfolio.  Retiring PNM’s share of SJGS would require future NMPRC approval.  PNM will also be required to obtain NMPRC approval of replacement power resources through CCN, PPA, or other applicable filings. The financial impact of an early retirement of SJGS and the NMPRC approval process are influenced by many factors outside of PNM’s control, including the economic impact of a potential SJGS abandonment on the area surrounding the plant and related mine, as well as overall political and economic conditions in New Mexico. Furthermore, PNM’s application for the abandonment of SJGS and for associated replacement resources would be significantly influenced by the requirements of the ETA. PNM will seek full recovery of its remaining undepreciated investments and other costs necessary to retire the SJGS and for replacement resources but, due to the uncertainty in obtaining the required approvals, PNM is unable to predict the outcome of this matter.

Other 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. 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

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CAA under which the Clean Power Plan exceeds EPA’s statutory authority. EPA published the proposed repeal rule on October 16, 2017 and accepted public comments through April 26, 2018. On August 31, 2018, EPA published a proposed rule, informally known as the Affordable Clean Energy rule, to replace the Clean Power Plan. The Affordable Clean Energy rule proposes GHG reductions be achieved through heat-rate improvement technologies identified as Best System of Emission Reduction (“BSER”). Under the proposed rule, states would determine and propose to EPA which technologies to apply to each coal-fired EGU and establish performance standards based on the degree of emission reduction achievable through application of the selected BSER (Note 11). Also, on December 20, 2018, EPA published in the Federal Register a proposed rule that would revise the carbon pollution standards rule issued in October 2015 for certain fossil fueled power plants. The proposal would revise the emissions standards for new, reconstructed, or modified coal-fired EGUs to make them less stringent. PNM estimates that implementation of the BART plan at SJGS, along with 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, the proposed Affordable Clean Energy rule, or any similar rule. PNM does not expect SJGS or Four Corners will be subject to the carbon pollution standards rule that EPA has proposed to revise. As discussed above and in Note 11, recent changes in New Mexico state law related to GHG emissions under the ETA may have significant impacts on SJGS and Four Corners as well as PNM’s other fossil-fueled generating resources. PNM is unable to predict the impact of these matters on its generation portfolio.

Major environmental upgrades on each of the units at SJGS have significantly reduced emissions of NOx, SO₂, particulate matter, and mercury. 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 2012 Mercury and Air Toxics Standards. Although EPA published a proposal on February 7, 2019 to reconsider some of the determinations underlying those standards, EPA has not proposed to alter the standards themselves. On the contrary, EPA determined that no more stringent standards are warranted because any residual risk remaining is acceptable within the margin of safety. Therefore, EPA’s 2019 proposal should not impact SJGS. Between 2006 and 2018, SJGS has reduced emissions of NOx by 77%, SO₂ by 92%, particulate matter by 88%, and mercury by 99%.

Renewable Energy

PNM’s renewable procurement strategy includes utility-owned solar capacity, as well as wind and geothermal energy purchased under PPAs. As discussed above, PNM is also considering the use of additional energy storage capacity in the event of an early retirement of SJGS. As of March 31, 2019, PNM has 117 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 106.8 MW at March 31, 2019. 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, which has a current capacity of 15 MW. PNM also purchases RECs as necessary to meet the RPS.

The majority of these renewable resources are key means for PNM to meet the RPS and related regulations that require PNM to achieve prescribed levels of energy sales from renewable sources, including those set by the recently enacted ETA, without exceeding cost requirements. PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM’s 2018 renewable energy procurement plan meets RPS and diversity requirements for 2018 and 2019 and includes additional procurements of wind, geothermal, and solar-PV capacity. PNM’s 2019 renewable energy procurement plan meets RPS and diversity requirements for 2019 and 2020 and does not include any significant new procurements. As discussed in Note 12, the ETA removes diversity requirements and certain customer caps and exemptions relating to the application of the RPS. As a result, PNM will be required to procure additional renewable resources to meet the 20% by 2020 requirement under the RPS, which would likely be obtained through PPAs with third-parties.

As discussed in Strategic Investments above, PNM is currently purchasing the output of 30 MW of solar capacity from NMRD that is used to serve the Facebook data center. 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 the Facebook data center. These PPAs include the purchase of the power and RECs from a 50 MW wind project, which was placed in commercial operation in November 2018, a 166 MW wind project to be operational in November 2020, and a 50 MW solar project to be operational in December 2021. In August 2018, the NMPRC approved PNM’s request to enter into two additional 25-year PPAs to purchase renewable energy and

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RECs from an aggregate of approximately 100 MW of capacity from two solar-PV facilities to be constructed by NMRD to supply power to Facebook. NMRD is required to obtain FERC approval of the PPAs. Subject to FERC approval, these facilities are expected to begin commercial operation by June 2020. See Note 12.

The ETA removes certain customer caps and exemptions relating to the application of the RPS. As a result of these changes, PNM will be required to procure additional energy from renewable resources to meet the 20% by 2020 requirement under the RPS. PNM expects to request NMPRC approval of a PPA for wind generation capacity, which would utilize the BB2 Line to deliver the power, to meet this requirement. See additional discussion of these matters in Note 12.

PNM will continue to procure renewable resources while balancing the impact to customers’ electricity costs in order to meet New Mexico’s escalating RPS and carbon-free resource requirements.

Energy Efficiency

Energy efficiency plays a significant role in helping to keep customers’ electricity costs low while meeting their energy needs and is one of the Company’s approaches to supporting environmentally responsible power. PNM’s and TNMP’s energy efficiency and load management portfolios continue to achieve robust results. In 2018, incremental energy saved as a result of new participation in PNM’s portfolio of energy efficiency programs was approximately 72 GWh. This is equivalent to the annual consumption of approximately 10,300 homes in PNM’s service territory. PNM’s load management and annual energy efficiency programs also help lower peak demand requirements. In 2018, TNMP’s incremental energy saved as a result of new participation in TNMP’s energy efficiency programs was approximately 17 GWh. This is equivalent to the annual consumption of approximately 1,500 homes in TNMP’s service territory. In April 2018, TNMP received the “Partner of the Year Energy Efficiency Delivery Award” for its High-Performance Homes Program.

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 has continued to decline as PNM has substituted less fresh-water-intensive generation resources to replace SJGS Units 2 and 3 starting in 2018, as water consumption at that plant has been reduced by approximately 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 2018, 19 of the Company’s 23 facilities met the solid waste diversion goal of a 65% diversion rate. 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 building 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 customer service 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.

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. The Company’s website is also a resource for information about PNM’s operations and community outreach efforts, including plans for building a sustainable energy future for New Mexico. PNM has also leveraged social media in communications with customers on various topics such as education, outage alerts, safety, customer service, and PNM’s community partnerships in philanthropic projects. In May 2017, a chat function was added to PNM’s website to provide customers options when communicating with customer service representatives and an online management system was launched to expedite applications for solar interconnections. In 2018, a program was implemented to increase communication and collaboration with large commercial and industrial customers.

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PNMR also has a dedicated Sustainability Portal on its corporate website www.pnmresources.comto 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 portal also includes information presented under the additional headings: Environment, Generation Portfolio, 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 consumer preparation when severe weather is forecasted. In August 2017, Hurricane Harvey made landfall in the gulf coast region and TNMP employees worked 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 electricity consumers to ensure that these stakeholders are updated on company investments and initiatives. Key electricity consumers 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, 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 innovate or sustain programs to grow and develop business, develop and implement environmental programs, and provide educational opportunities. PNMR also provides employee matching and volunteer grants for various purposes. In early 2018, the PNM Resources Foundation awarded five grants of $0.2 million each, to be paid over two years, to a number of not-for-profit organizations to support their efforts in areas such as assisting businesses, supporting education, and other economic development efforts. Recipients included the New Mexico State University College of Engineering, to support education for professional surveyors, Central New Mexico Community College, and other local economic organizations to support workforce and small business education programs.

Over the past six years, the Company has contributed a total of more than $7.0 million to civic, educational, environmental, low income, and economic development organizations. PNMR is proud to support programs and organizations that enrich the quality of life for the people in its service territories and communities. One of PNM’s most important outreach programs is tailored for low-income customers. In 2018, PNM hosted 50 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 3,811 families in 2018 and offered financial literacy training to further support customers.

Volunteerism is an important facet of the PNMR culture. The mission of the PNMR Corporate Volunteer Group is to help make the communities in which PNMR serves safer, stronger, smarter, and more vibrant. In 2018, PNM and TNMP employees and retirees contributed approximately 11,500 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 the three months ended March 31, 2019, PNM experienced an increase in weather-normalized retail load of 1.2% compared to 2018. Economic conditions in Albuquerque have continued to improve in the first quarter of 2019 and PNM continues to experience load growth in its service areas, particularly in the industrial customer class. In 2018, Netflix, Inc., announced plans to make significant investments in production in New Mexico, and activities related to the construction of a data center by Facebook, Inc., are continuing to progress.

TNMP –In the three months ended March 31, 2019, TNMP experienced a decrease in volumetric weather-normalized retail load of 1.9% compared to 2018. Demand-based load, excluding retail transmission customers, increased 4.7% in the three months ended March 31, 2019 compared to 2018. Revised rates implemented in January 2019 re-balance charges between wholesale transmission and retail distribution customers and other changes to rate design allocate more revenues to customers billed on a volumetric basis, resulting in lower earnings in the first quarter 2019 when compared to 2018. The Texas economy continues to grow and TNMP continues to see new requests to interconnect to its system.

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Results of Operations

Net earnings attributable to PNMR were $18.7 million, or $0.23 per diluted share in the three months ended March 31, 2019 compared to $15.0 million, or $0.19 per diluted share, in 2018. Among other things, earnings in the three months ended March 31, 2019 benefited from additional revenues due to the rate increases approved in PNM’s NM 2016 Rate Case and TNMP’s 2018 Rate Case, higher revenues under FERC formula transmission rates and new transmission customers at PNM, increased weather and load at PNM, higher income from investment securities held in the NDT and coal mine reclamation trusts, and lower interest expense at PNM. These increases were offset by additional regulatory disallowances related to PNM’s appeal of the NMPRC’s decisions in the NM 2015 Rate Case, reduced revenues at PNM under its rate riders, lower transmission cost of service revenues as a result of a reallocation of costs in TNMP’s 2018 Rate Case, higher employee related expenses at PNM and TNMP, increased depreciation and property taxes due to increased plant in service at PNM and TNMP, as well as increased depreciation rates resulting from TNMP’s 2018 Rate Case, higher interest expense at TNMP as a result of debt issued in the second half of 2018, and lower interest income on the Westmoreland Loan at PNMR. Additional information on factors impacting results of operation for each segment is discussed below under Results of Operations.

Liquidity and Capital Resources

PNMR and PNM have revolving credit facilities with capacities of $300.0 million and $400.0 million and currently expire in October 2023. Both facilities provide for short-term borrowings and letters of credit and can be extended through October 2024, subject to approval by a majority of the lenders. 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. On February 22, 2019, PNMR Development amended its revolving credit facility to increase the capacity to $25.0 million and to extend its expiration date to February 24, 2020. The PNMR Development Revolving Credit Facility bears interest at a variable rate and contains terms similar to the PNMR Revolving Credit Facility. Total availability for PNMR on a consolidated basis was $732.5 million at May 3, 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, capital contributions for PNMR Development’s 50% ownership interest in NMRD, and dividends, will total $3,627.7 million for 2019-2023, including amounts expended through March 31, 2019. 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, and an anticipated expansion of PNM’s transmission system.

On January 18, 2019, PNM entered into the $250.0 million PNM 2019 Term Loan, which bears interest at a variable rate and must be repaid on or before July 17, 2020. Proceeds from this issuance were used to repay the PNM 2017 Term Loan, short-term borrowings under the PNM Revolving Credit Facility, and for other general corporate purposes. On February 26, 2019, TNMP entered into the TNMP 2019 Bond Purchase Agreement which provides for the sale of $305.0 million aggregate principal amount of TNMP 2019 Bonds. TNMP issued $225.0 million of TNMP 2019 Bonds on March 29, 2019 (at fixed annual interest rates ranging from 3.79% to 4.06% for terms ranging from 15 to 25 years) and used a portion of the proceeds to repay TNMP’s $172.3 million 9.50% first mortgage bonds at their maturity on April 1, 2019. TNMP will issue the remaining $80.0 million of TNMP 2019 Bonds on or before July 1, 2019 (at a fixed annual interest rate of 3.60% for a term of ten years) and will use the proceeds to repay borrowings under the TNMP Revolving Credit Facility and for other general corporate purposes.

After considering the effects of these financings, PNMR has consolidated maturities and other repayments of short-term and long-term debt aggregating $150.0 million in the period from April 1, 2019 through March 31, 2020, and an additional $525.3 million that will mature by December 31, 2020. In addition to internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing in the form of debt refinancing, new debt issuances, and/or new equity in order to fund its capital requirements during the 2019-2023 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 at least 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 Condensed Consolidated Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known. Refer also to Disclosure Regarding Forward Looking Statements and to Part II, Item 1A. Risk Factors.

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

	Three Months Ended March 31,
	2019		2018		Change
	(In millions, except per share amounts)
Net earnings attributable to PNMR	$	18.7	$	15.0	$	3.7
Average diluted common and common equivalent shares	80.0		80.0		—
Net earnings attributable to PNMR per diluted share	$	0.23	$	0.19	$	0.04

The components of the change in net earnings attributable to PNMR are:

	Three Months Ended
	March 31, 2019
	(In millions)
PNM	$	11.3
TNMP	(5.3		)
Corporate and Other	(2.3		)
Net change	$	3.7

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

Segment Information

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

PNM

PNM 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 under PNM’s FPPAC. 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 PNM:

	Three Months Ended March 31,
	2019			2018			Change
	(In millions)
Electric operating revenues	$	269.3		$	236.2		$	33.1
Cost of energy	99.3			70.8			28.5
Utility margin	170.0			165.4			4.6
Operating expenses	106.5			100.5			6.0
Depreciation and amortization	39.2			36.6			2.6
Operating income	24.3			28.3			(4.0		)
Other income (deductions)	18.0			3.7			14.3
Interest charges	(18.4		)	(20.8		)	2.4
Segment earnings before income taxes	23.9			11.2			12.7
Income (taxes) benefit	(2.0		)	0.3			(2.3		)
Valencia non-controlling interest	(2.8		)	(3.7		)	0.9
Preferred stock dividend requirements	(0.1		)	(0.1		)	—
Segment earnings	$	19.0		$	7.7		$	11.3

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

	Three Months Ended March 31,
			Percentage
	2019	2018	Change
	(Gigawatt hours, except customers)
Residential	795.5	751.7	5.8	%
Commercial	828.2	834.4	(0.7	)
Industrial	250.0	205.7	21.5
Public authority	49.6	50.3	(1.4	)
Economy energy service (1)	156.9	170.7	(8.1	)
Other sales for resale	874.7	681.0	28.4
	2,954.9	2,693.8	9.7	%
Average retail customers (thousands)	529.1	524.7	0.8	%

⁽¹⁾ PNM purchases energy for a large 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 only a minor impact in utility margin resulting from providing ancillary services.

Operating Results – Three months ended March 31, 2019 compared to 2018

The following table summarizes the significant changes to utility margin:

		Three Months Ended March 31, 2019
		Change
Utility margin:		(In millions)
	Rate relief – Additional revenue due to rate increase approved by the NMPRC effective February 1, 2018 (Note 12)	$	1.7
	Retail customer usage/load –Weather normalized KWh sales increased 1.2% due to increased sales to residential and industrial customers	1.6
	Weather – Colder weather in 2019; heating degree days were 23.8% higher	2.8
	Transmission –Increase primarily due to the addition of new customers	1.1
	Rate riders –Includes renewable energy, fuel clause and energy efficiency riders	(2.8		)
	Other	0.2
	Net Change	$	4.6

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

		Three Months Ended March 31, 2019
		Change
Operating expenses:		(In millions)
	Lower plant maintenance costs at Four Corners and PVNGS, offset by higher costs at SJGS and gas-fired plants	$	(0.3	)
	Accelerated recovery of SNCR technology on SJGS Units 1 and 4	0.3
	Regulatory disallowance resulting from the NMPRC’s September 28, 2016 order in PNM’s NM 2015 Rate Case (Note 12)	1.3
	Higher property taxes due to increases in utility plant in service	0.4
	Higher employee related, outside service, and vegetation management expenses	3.9
	Other	0.4
	Net Change	$	6.0

Depreciation and amortization:
	Increased utility plant in service	$	1.7
	Higher depreciation resulting from amortization of stranded costs associated with the retirement of SJGS Units 2 and 3	0.5
	Other	0.4
	Net Change	$	2.6

Other income (deductions):
	Higher gains in 2019 compared to 2018 on investment securities in the NDT and coal mine reclamation trusts	$	13.7
	Lower equity AFUDC	(0.2		)
	Higher interest income related to investment securities in the NDT and coal mine reclamation trusts, partially offset by higher trust expenses	0.6
	Other	0.2
	Net Change	$	14.3

Interest charges:
	Lower interest on $350.0 million of SUNs refinanced in May 2018	$	3.9
	Lower interest on $100.0 million of SUNs refinanced in August 2018	0.8
	Lower debt AFUDC	(0.7		)
	Higher interest on term loan agreements	(0.7		)
	Interest on deposit by PNMR Development for potential transmission interconnections, which is offset in Corporate and Other (Note 9)	(0.9		)
	Net Change	$	2.4

Income taxes:
	Increase due to higher segment earnings before income taxes	$	(3.6	)
	Decrease due to higher amortization of excess deferred income taxes due to higher pre-tax earnings	1.9
	Increase due to lower excess tax benefits related to stock compensation awards (Note 8)	(0.5		)
	Other	(0.1		)
	Net Change	$	(2.3	)

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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 consumers 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:

	Three Months Ended March 31,
	2019			2018			Change
	(In millions)
Electric operating revenues	$	80.3		$	81.6		$	(1.3	)
Cost of energy	22.3			21.8			0.5
Utility margin	58.0			59.9			(1.9		)
Operating expenses	25.2			25.0			0.2
Depreciation and amortization	20.2			16.4			3.8
Operating income	12.6			18.5			(5.9		)
Other income (deductions)	0.6			1.1			(0.5		)
Interest charges	(8.8		)	(7.7		)	(1.1		)
Segment earnings before income taxes	4.4			11.9			(7.5		)
Income (taxes)	(0.3		)	(2.5		)	2.2
Segment earnings	$	4.1		$	9.4		$	(5.3	)

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

	Three Months Ended March 31,
			Percentage
	2019	2018	Change
Volumetric load (1) (GWh)
Residential	618.7	656.8	(5.8	)%
Commercial and other	7.9	8.0	(1.3	)
Total volumetric load	626.6	664.8	(5.7	)%
Demand-based load (2) (MW)	4,721.9	4,310.2	9.6	%
Average retail consumers (thousands)(3)	253.8	250.1	1.5	%

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

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

⁽³⁾ TNMP provides transmission and distribution services to REPs that provide electric service to their 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.

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Operating Results – Three months ended March 31, 2019 compared to 2018

The following table summarizes the significant changes to utility margin:

		Three Months Ended March 31, 2019
		Change
Utility margin:		(In millions)
	Retail rate relief – TNMP 2018 Rate Case retail rate increase effective January 1, 2019, including integration of amounts previously recovered in the AMS rate rider and the impact of rate design changes between customer classes (Note 12)	$	1.2
	Transmission rate relief - Decrease in transmission cost of service rates primarily resulting from the TNMP 2018 Rate Case	(2.5		)
	Retail customer usage/load –Weather normalized KWh sales decreased 1.9%; the average number of retail consumers increased 1.5%	(0.4		)
	Demand-based customer usage/load - Higher demand-based revenues for large commercial and industrial customers; billed demand excluding retail transmission customers increased 4.7%.	0.7
	Weather – Milder weather in 2019; heating degree days were 18.6% lower in January 2019 resulting from unusually cold weather in January 2018	(0.9		)
	Net Change	$	(1.9	)

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

		Three Months Ended March 31, 2019
		Change
Operating expenses:		(In millions)
	Higher employee related expenses	$	0.9
	Higher capitalization of administrative and general expenses due to higher construction expenditures	(0.7		)
	Higher property taxes due to increased utility plant in service	0.4
	Lower vegetation management expenses	(0.3		)
	Other	(0.1		)
	Net Change	$	0.2

Depreciation and amortization:
	Increased utility plant in service	$	1.1
	Higher depreciation rates approved in the TNMP 2018 Rate Case	2.3
	Higher amortization of AMS and Hurricane Harvey regulatory assets approved in the TNMP 2018 Rate Case (Note 12)	0.5
	Other	(0.1		)
	Net Change	$	3.8

Other income (deductions):
	Lower equity AFUDC	$	(0.2	)
	Lower CIAC	(0.1		)
	Other	(0.2		)
	Net Change	$	(0.5	)

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		Three Months Ended March 31, 2019
		Change
Interest charges:		(In millions)
	Increase due to issuance of $60.0 million of long-term debt in June 2018	$	(0.6	)
	Increase due to issuance of $20.0 million term loan in July 2018 and $15.0 million in December 2018	(0.3		)
	Other	(0.2		)
	Net Change	$	(1.1	)

Income taxes:
	Decrease due to lower segment earnings before income taxes	$	1.6
	Decrease due to amortization of excess deferred federal income taxes (Note 14)	0.7
	Increase due to lower excess tax benefits related to stock compensation awards	(0.1		)
	Net Change	$	2.2

Corporate and Other

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

	Three Months Ended March 31,
	2019			2018			Change
	(In millions)
Electric operating revenues	$	—		$	—		$	—
Cost of energy	—			—			—
Utility margin	—			—			—
Operating expenses	(5.8		)	(5.0		)	(0.8		)
Depreciation and amortization	5.9			5.7			0.2
Operating income (loss)	(0.2		)	(0.7		)	0.5
Other income (deductions)	(0.8		)	1.7			(2.5		)
Interest charges	(4.5		)	(4.5		)	—
Segment earnings (loss) before income taxes	(5.4		)	(3.5		)	(1.9		)
Income (taxes) benefit	1.0			1.3			(0.3		)
Segment earnings (loss)	$	(4.4	)	$	(2.1	)	$	(2.3	)

Corporate and Other operating expenses shown above are net of amounts allocated to PNM and TNMP under shared services agreements. The change in depreciation and amortization expense primarily relates to additions to computer software. Substantially all depreciation and amortization expense and other income (deductions) are offset in operating expenses as a result of allocation of these costs to other business segments.

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Operating Results – Three months ended March 31, 2019 compared to 2018

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

		Three Months Ended March 31, 2019
		Change
Other income (deductions):		(In millions)
	Decrease in interest income on the Westmoreland Loan	$	(1.7	)
	Increase in donations and other contributions	(0.5		)
	Other	(0.3		)
	Net Change	$	(2.5	)

Interest charges:
	Issuance of $300.0 million PNMR 2018 SUNs in March 2018	$	(1.8	)
	Issuance of $90.0 million PNMR Development Term Loan in November 2018	(0.8		)
	Lower short-term borrowings	0.5
	Repayment of $150.0 million PNMR 2015 Term Loan in March 2018	0.7
	Repayment of the BTMU Term Loan in May 2018	0.6
	Elimination of intercompany interest (Note 9)	0.9
	Other	(0.1		)
	Net Change	$	—

Income taxes:
	Impact of difference in effective tax rates used by PNMR and its subsidiaries in the calculation of income taxes in interim periods	$	(1.0	)
	Decrease due to larger segment loss before income taxes	0.5
	Other	0.2
	Net Change	$	(0.3	)

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR’s cash flows for the three months ended March 31, 2019 compared to March 31, 2018 are summarized as follows:

	Three Months Ended March 31,
	2019			2018			Change
	(In millions)
Net cash flows from:
Operating activities	$	104.7		$	78.9		$	25.8
Investing activities	(151.9		)	(119.2		)	(32.7		)
Financing activities	225.2			40.1			185.1
Net change in cash and cash equivalents	$	178.0		$	(0.2	)	$	178.2

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.    

101

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 purchases and sales of investment securities in the NDT and coal mine reclamation trusts, including activity to rebalance the investment portfolio in early 2018. In addition, cash flows from investing activities include activity related to the Westmoreland Loan, which was paid in full in May 2018, and NMRD. Major components of PNMR’s cash inflows and (outflows) from investing activities are shown below:

	Three Months Ended March 31,
	2019			2018			Change
Cash (Outflows) for Utility Plant Additions	(In millions)
PNM:
Generation	$	(40.6	)	$	(18.0	)	$	(22.6	)
Transmission and distribution	(29.2		)	(33.0		)	3.8
Four Corners SCRs	—			(3.8		)	3.8
Nuclear fuel	(6.1		)	(6.9		)	0.8
	(75.9		)	(61.7		)	(14.2		)
TNMP:
Transmission	(27.5		)	(23.2		)	(4.3		)
Distribution	(31.1		)	(26.8		)	(4.3		)
	(58.6		)	(50.0		)	(8.6		)
Corporate and Other:
Computer hardware and software	(7.4		)	(6.0		)	(1.4		)
	(7.4		)	(6.0		)	(1.4		)
Total cash (outflows) for additions to utility plant	$	(141.9	)	$	(117.7	)	$	(24.2	)
Other Cash Flows from Investing Activities
Proceeds from sales of investment securities	$	74.5		$	626.7		$	(552.2	)
Purchases of investment securities	(77.4		)	(628.9		)	551.5
Principal payments on the Westmoreland Loan	—			5.6			(5.6		)
Investments in NMRD	(7.0		)	(5.0		)	(2.0		)
Other, net	(0.1		)	0.1			(0.2		)
Total cash (outflows) from investing activities	$	(151.9	)	$	(119.2	)	$	(32.7	)

Cash Flow from Financing Activities

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

• Short-term borrowings decreased $12.1 million in 2019 compared to a decrease of $66.7 million in 2018, resulting in a net increase in cash flows from financing activities of $54.6 million

• In 2019, PNM borrowed $250.0 million under the PNM 2019 Term Loan and used the proceeds to repay the $200.0 million PNM 2017 Term Loan

• In 2019, TNMP issued $225.0 million of TNMP 2019 Bonds

Financing Activities

See Note 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and Note 9 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

102

Each of the Company’s revolving credit facilities and term loans contain a single financial covenant that requires the maintenance of a debt-to-capitalization ratio. For the PNMR and PNMR Development agreements, this ratio must be maintained at less than or equal to 70%, and for the PNM and TNMP agreements this ratio must be maintained at less than or equal to 65%. The Company’s revolving credit facilities and term loans generally also contain customary covenants, events of default, cross-default provisions, and change-of-control provisions. The Company is in compliance with its debt covenants.

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 WSJ LLC is required to post in connection with permits relating to the operation of the San Juan mine (Note 11).

On January 18, 2019, PNM entered into a $250.0 million term loan agreement (the “PNM 2019 Term Loan”) among PNM, the lenders identified therein, and U.S. Bank N.A., as administrative agent. PNM used the proceeds of the PNM 2019 Term Loan to repay the PNM 2017 Term Loan, to reduce short-term borrowings under the PNM Revolving Credit Facility, and for general corporate purposes. The PNM 2019 Term Loan bears interest at a variable rate and must be repaid on or before July 17, 2020.

On February 26, 2019, TNMP entered into the TNMP 2019 Bond Purchase Agreement with institutional investors for the sale of $305.0 million aggregate principal amount of four series of TNMP first mortgage bonds (the “TNMP 2019 Bonds”) offered in private placement transactions. Under the TNMP 2019 Bond Purchase Agreement, TNMP issued $225.0 million of the TNMP 2019 Bonds on March 29, 2019 (at fixed annual interest rates ranging from 3.79% to 4.06% for terms ranging from 15 to 25 years) and used the proceeds to repay TNMP’s $172.3 million 9.50% first mortgage bonds at their maturity on April 1, 2019, as well as to repay borrowings under the TNMP Revolving Credit Facility and for general corporate purposes. TNMP will issue the remaining $80.0 million of the TNMP 2019 Bonds on or before July 1, 2019 (at a fixed annual interest rate of 3.60% for a term of ten years) and will use the proceeds to repay borrowings under the TNMP Revolving Credit Facility and for other general corporate purposes. The issuance of the remaining TNMP 2019 Bonds is subject to the satisfaction of customary conditions, and the TNMP 2019 Bonds are subject to continuing compliance with the representations, warranties and covenants of the TNMP 2019 Bond Purchase Agreement. The terms of the TNMP 2019 Bonds contain customary covenants, including a covenant that requires TNMP to maintain a debt-to-capitalization ratio of less than or equal to 65%, customary events of default, a cross-default provision, and a change-of-control provision. TNMP will have the right to redeem any or all of the TNMP 2019 Bonds prior to their respective maturities, subject to payment of a customary make-whole premium. In accordance with GAAP, borrowings under the $172.3 million9.50% TNMP first mortgage bonds are reflected as being long-term in the Condensed Consolidated Balance Sheets at December 31, 2018 since TNMP demonstrated its intent and ability to re-finance the agreement on a long-term basis. These bonds are reflected in current maturities of long-term debt on the Condensed Consolidated Balance Sheets at March 31, 2019 since the proceeds from the issuance of $225.0 million of TNMP 2019 Bonds, net of amounts used to repay short-term debt, are reflected in cash and cash equivalents.

In 2017, PNMR entered into three separate four-year hedging agreements whereby it effectively established fixed interest rates on three separate tranches, each of $50.0 million, of its variable rate debt. The hedging agreements effectively fix interest rates on the aggregate $150.0 million of short-term debt at rates of 1.926%, 1.823%, and 1.629%, plus customary spreads over LIBOR, and are subject to changes if there is a change in PNMR’s credit rating.

Capital Requirements

PNMR’s total capital requirements consist of construction expenditures, cash dividend requirements for PNMR common stock and PNM preferred stock, and capital contributions for PNMR Development’s 50% ownership interest in NMRD. Key activities in PNMR’s current construction program include:

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

• Expanding the electric transmission and distribution systems

• Purchasing nuclear fuel

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Projected capital requirements, including amounts expended through March 31, 2019, are:

	2019		2020-2023		Total
	(In millions)
Construction expenditures	$	604.5	$	2,495.1	$	3,099.6
Capital contributions to NMRD	29.9		33.6		63.5
Dividends on PNMR common stock	92.4		369.6		462.0
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	727.3	$	2,900.4	$	3,627.7

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 $60.0 million for 50 MW of new solar facilities included in PNM’s 2018 renewable energy procurement plan, and approximately $125.0 million in 2019-2020 for anticipated expansions of PNM’s transmission system. Also included in the table above is a net amount of approximately $285 million in 2021 for PNM’s May 1, 2019 agreement to purchase a 165-mile 345 kV transmission line and to construct associated facilities (the “Western Spirit Line”), subject to NMPRC and FERC approval. PNM anticipates the Western Spirit line will be used to serve approximately 800 MW of new wind generation facilities in eastern New Mexico. Not included in the table above are potential incremental expenditures for replacement resources related to the planned shutdown of SJGS Units 1 and 4 in 2022. PNM will be required to file CCN applications or submit other filings with the NMPRC for approval to shut down SJGS and for related replacement resources. See Note 11 and 12. 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 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP.

During the three months ended March 31, 2019, 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. As discussed above, on February 26, 2019 TNMP entered into the TNMP 2019 Bond Purchase Agreement providing for the issuance of an aggregate of $305.0 million of TNMP 2019 Bonds. TNMP issued $225.0 million of the TNMP 2019 Bonds on March 29, 2019 and used a portion of the proceeds from that issuance to repay TNMP’s $172.3 million 9.50% first mortgage bonds at their maturity on April 1, 2019. TNMP will issue the remaining $80.0 million of TNMP 2019 Bonds on or before July 1, 2019 and will use the proceeds from that issuance to repay borrowings under the TNMP Revolving Credit Facility and for other general corporate purposes. In addition, the $150.0 million PNMR 2018 One-Year term loan will mature in December 2019. Note 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K contains additional information about the maturities of long-term debt. The Company anticipates that funds to repay long-term debt maturities and term loans will come from entering into new arrangements similar to the existing agreements, borrowing under the revolving credit facilities, issuance of new long-term debt or equity 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. The PNMR and PNM facilities currently expire on October 22, 2023 but can be extended through October 2024, subject to approval by a majority of the lenders. The $75.0 million TNMP Revolving Credit Facility matures in September 2022. PNM also has the $40.0 million PNM 2017 New Mexico Credit Facility that 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.

On February 22, 2019 PNMR Development amended its revolving credit facility to increase the capacity to $25.0 million and to extend the term until February 24, 2020. 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 uses the facility to finance its participation in NMRD and for other activities (Note 1).

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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 March 31, 2019
Range of Borrowings	Low		High
	(In millions)
PNM:
PNM Revolving Credit Facility	$	—	$	40.0
PNM 2017 New Mexico Credit Facility	—		10.0
TNMP Revolving Credit Facility	—		45.5
PNMR Revolving Credit Facility	20.0		71.1
PNMR Development Revolving Credit Facility	6.0		11.6

At March 31, 2019, the average interest rates were 3.74% for the PNMR Revolving Credit Facility, 3.24% for the PNMR 2018 One-Year Term Loan, and 3.49% for the PNMR Development Revolving Credit Facility.

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 2019-2023 period. This could include new debt and/or equity issuances. The Company anticipates utilizing an at-the-market equity issuance program, or other program such as mandatory convertible securities, to raise equity beginning in 2020 to partially fund capital requirements. 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.

Information concerning the credit ratings for PNMR, PNM, and TNMP was set forth under the heading Liquidity in the MD&A contained in the 2018 Annual Reports on Form 10-K. As of May 3, 2019, ratings on the Company’s securities were as follows:

	PNMR	PNM	TNMP
S&P
Corporate rating	BBB+	BBB+	BBB+
Senior secured debt	*	*	A
Senior unsecured debt	BBB	BBB+	*
Preferred stock	*	BBB-	*
Moody’s
Issuer rating	Baa3	Baa2	A3
Senior secured debt	*	*	A1
Senior unsecured debt	Baa3	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. On January 16, 2018, S&P changed the outlook for PNMR, PNM, and TNMP from stable to negative while affirming the ratings above for all the entities. On June 29, 2018, Moody’s changed the ratings outlook for PNMR and PNM from positive to stable, maintained the stable outlook for TNMP, and affirmed the long-term credit ratings of each entity. The ultimate outcomes from PNM’s NM 2015 Rate Case, including the pending appeal before the NM Supreme Court, as discussed in Note 12, could affect both the outlook and credit ratings. Investors are cautioned that a security rating is not a recommendation to buy, sell, or hold

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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 May 3, 2019 is as follows:

	PNM		TNMP		PNMR Separate		PNMR Development		PNMR Consolidated
	(In millions)
Financing capacity:
Revolving credit facility	$	400.0	$	75.0	$	300.0	$	25.0	$	800.0
PNM 2017 New Mexico Credit Facility	40.0		—		—		—		40.0
Total financing capacity	$	440.0	$	75.0	$	300.0	$	25.0	$	840.0
Amounts outstanding as of May 3, 2019:
Revolving credit facility	$	—	$	29.2	$	55.9	$	15.1	$	100.2
PNM 2017 New Mexico Credit Facility	—		—		—		—		—
Letters of credit	2.5		0.1		4.7		—		7.3
Total short-term debt and letters of credit	2.5		29.3		60.6		15.1		107.5
Remaining availability as of May 3, 2019	$	437.5	$	45.7	$	239.4	$	9.9	$	732.5
Invested cash as of May 3, 2019	$	9.0	$	—	$	0.9	$	—	$	9.9

In addition to the above, PNMR has $30.3 million of letters of credit outstanding under the JPM LOC Facility. The above table excludes intercompany debt. As of May 3, 2019, PNM and TNMP had no intercompany borrowings from PNMR. The remaining availability under the revolving credit facilities at any point in time varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures.

PNMR has an automatic shelf registration that provides for the issuance of various types of debt and equity securities that expires in March 2021. 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. These arrangements help ensure PNM the availability of lower-cost generation needed to serve customers. See MD&A – Off-Balance Sheet Arrangements and Notes 7 and 9 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, as well as Note 13.

Commitments and Contractual Obligations

PNMR, PNM, and TNMP have contractual obligations for long-term debt, operating leases, construction expenditures, purchase obligations, and certain other long-term obligations. See MD&A – Commitments and Contractual Obligations in the 2018 Annual Reports on Form 10-K.

Contingent Provisions of Certain Obligations

As discussed in the 2018 Annual Reports on Form 10-K,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 contingent provisions also include contractual increases in the interest rate charged on certain of the Company’s short-term debt obligations in the event of a downgrade in credit ratings. 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.

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Capital Structure

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

	March 31, 2019		December 31, 2018
PNMR
PNMR common equity	36.3	%	38.6	%
Preferred stock of subsidiary	0.2		0.3
Long-term debt	63.5		61.1
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	45.3	%	45.6	%
Preferred stock	0.4		0.4
Long-term debt	54.3		54.0
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	45.5	%	53.9	%
Long-term debt	54.5		46.1
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 enacted and potential federal and/or state regulation of GHG; plans to mitigate these risks; and the impacts these risks may have on the Company’s strategy. In addition, the Board approves certain procurements of environmental equipment, grid modernization technologies, and replacement generation resources.

Management is also responsible for assessing significant risks, developing and executing appropriate responses, and reporting to the Board on the status of risk activities. For example, management periodically updates the Board on the implementation of corporate environmental policy, and the Company’s environmental management systems, including the promotion of energy efficiency programs, and the use of renewable resources.  The Board is also informed of the Company’s practices and procedures to assess the impacts of operations on the environment. The Board considers issues associated with climate change, the Company’s GHG exposures, and the financial consequences that might result from enacted and potential federal and/or state regulation of GHG. Management has 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 an emissions-free generating portfolio by 2040.

As part of management’s continuing effort to monitor climate-related risks and opportunities, the Company is evaluating different climate change disclosure frameworks, including the framework created by the Task Force on Climate-related Financial Disclosures and a framework created by Edison Electric Institute. The Company is also participating in an Electric Power Research Institute project that is analyzing climate change scenarios and GHG goal setting.

The Company cannot anticipate or predict the potential long-term effects of climate change or climate change related regulation on its assets and operations.

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Greenhouse Gas Emissions Exposures

In 2018, GHG associated with PNM’s interests in its fossil-fueled generating plants included approximately 5.1 million metric tons of CO₂, which comprises the vast majority of PNM’s GHG.

As of December 31, 2018, approximately 66% 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 caused the Company’s output of GHG to decrease when 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 2018, 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 generation resource portfolio, thereby reducing its exposure to climate change regulation. See Note 12. As described in Note 16 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, 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 resulted in a reduction of GHG for the entire station of approximately 54%, reflecting a reduction of 41% of GHG from the Company’s owned interests in SJGS, below 2005 levels. On December 31, 2018, PNM submitted a compliance filing notifying the NMPRC that, consistent with the conclusions reached in the 2017 IRP, PNM’s customers would benefit from the retirement of SJGS in 2022. In addition, as discussed in Note 12, PNM’s 2017 IRP also indicates exiting ownership in Four Corners in 2031 would provide long-term cost savings to its customers. If approved by the NMPRC, retiring PNM’s share of SJGS and exiting participation in Four Corners would further reduce PNM’s GHG. PNM owns utility-scale solar generation in commercial operation with a total generation capacity of 117 MW as of March 31, 2019. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has a contract 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 15 MW. On November 15, 2017 the NMPRC approved PNM’s 2018 renewable energy procurement plan. 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 and 2019. Additionally, PNM began purchasing renewable energy from 30 MW of solar-PV facilities owned by NMRD in 2018 and, subject to FERC approval, will purchase an additional 100 MW of capacity from solar-PV facilities to be owned by NMRD in 2019 and 2020 to supply power to a data center being constructed in PNM’s service territory (Note 12). In December 2018, PNM began purchasing 50 MW of renewable energy from Casa Mesa Wind, which is also being used to support the data center in PNM’s service territory. PNM also has a customer distributed solar generation program that represented 106.8 MW at March 31, 2019. PNM’s distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 213.6 GWh. PNM has offered its customers a comprehensive portfolio of energy efficiency and load management programs since 2007. PNM’s cumulative annual savings from these programs were approximately 653 GWh of electricity in 2018. Over the next 20 years, PNM projects energy efficiency and load management programs will provide the equivalent of approximately 7,700 GWh of electricity, which will avoid at least 4.2 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 could adversely impact PNM.

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

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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 other extreme weather 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. In addition, other events influenced by climate change, such as wildfires, could disrupt Company operations or result in third-party claims against the Company.

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 GHG 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 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. However, the court upheld EPA’s authority to apply the PSD program for GHG 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, which were published in October 2015: (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 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, but the new unit standards were based on EPA’s determination that the BSER for new units was partial carbon recapture and sequestration. 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 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 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.

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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 accepted comments on that proposed interpretation through April 26, 2018. Any final rule will likely be subject to judicial review. On December 18, 2017, EPA released an advanced NOPR addressing GHG guidelines for existing electric utility generating units. On August 31, 2018, EPA published a proposed rule, which is informally known as the Affordable Clean Energy rule, to replace the Clean Power Plan. The proposed Affordable Clean Energy rule, among other things, would establish guidelines that replace the “outside-the-fenceline” control measures and specific numerical emission rates for existing EGUs with a list of “candidate technologies” for heat rate improvement measures that EPA has identified as BSER. States would determine which of the candidate technologies to apply to each coal-fired unit and establish standards of performance based on the degree of emission reduction achievable once BSER is applied. States will have three years from when the rule is finalized to submit a plan to EPA and EPA will have one year to determine if each proposed plan is acceptable. If states do not submit a plan, or if their submitted plan is not acceptable, EPA will have two years to develop a federal plan. EPA is also proposing revisions to NSR program that would provide coal-fired power plants more latitude to make efficiency improvements consistent with BSER without triggering NSR permit requirements. Comments on the proposed Affordable Clean Energy rule were due to EPA by October 31, 2018.

On December 20, 2018, EPA published in the Federal Register a proposed rule that would revise the Carbon Pollution Standards rule published in October 2015 for new, reconstructed, or modified coal-fired EGUs. The proposed rule would revise the standards for new coal-fired EGUs based on the revised BSER as the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units), instead of partial carbon recapture and sequestration, which results in less stringent CO₂ emission performance standards for new units. EPA has also proposed revisions to the standards for reconstructed and modified fossil-fueled power plants to align with the proposed standards for new units. EPA is not proposing any changes nor reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. Comments on the proposal were due on March 18, 2019.

PNM is unable to predict the impact to the Company of these proposed rulemakings. If a future regulation limiting or otherwise reducing GHG from fossil-fueled EGUs is adopted, such regulations could impact PNM’s existing and future fossil-fueled EGUs. The proposed Carbon Pollution Standards rule could also impact PNM’s generation fleet to the extent any EGUs qualify as new, reconstructed, or modified, 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 unlikely in 2019.  Although the new democratic leadership in the U.S. House of Representatives may soon begin to reconsider proposals for legislation aimed at addressing climate change, such legislation is unlikely to pass the republican controlled U.S. Senate or be signed by the President.

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.  In its 2017 IRP, PNM analyzed resource portfolio plans for scenarios that assumed SJGS will operate

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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 as discussed in Note 12. The key findings of the 2017 IRP include that exiting SJGS in 2022 would provide long-term economic 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. See additional discussion of PNM’s December 2018 Compliance filing in Note 11, which indicates PNM plans to retire SJGS after the SJGS CSA expires in mid-2022.

On March 22, 2019, Senate Bill 489, known as the Energy Transition Act (“ETA”) was signed into New Mexico state law and becomes effective on June 14, 2019. The ETA, among other things, requires that investor-owned utilities obtain specified percentages of their energy from renewable and carbon-free resources. Prior to the enactment of the ETA, the REA established a mandatory RPS requiring utilities to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA provides for a transition from coal-fired generating resources to carbon-free resources by allowing investor-owned utilities to issue securitized bonds, or “energy transition bonds,” related to the retirement of coal-fired generating facilities to qualified investors. Proceeds from the energy transition bonds must be used only for purposes related to providing utility service to customers and to pay “financing costs” (as defined by the ETA). These costs may include coal mine decommissioning, plant decommissioning, and other costs that have not yet been charged to customers or disallowed by the NMPRC or by a court order. Proceeds provided by energy transition bonds may also be used to pay for severances for employees of the retired coal-fired generating facility and related coal mine, as well as to pay for job training, education, and economic development. Energy transition bonds must be issued under an NMPRC financing order and are paid by a non-bypassable charge paid by all customers of the issuing utility. The ETA also amends sections of the REA to allow for the recovery of undepreciated investments and decommissioning costs related to qualifying EGUs that the NMPRC has required be removed from retail jurisdictional rates, provided replacement resource to be included in retail rates have lower or zero-carbon emissions. The ETA requires the NMPRC to prioritize replacement resources in a manner intended to mitigate the economic impact to communities affected by these plant retirements. See additional discussion of the ETA in Note 11. The effectiveness of the ETA will have a significant impact on PNM’s future generation portfolio, including PNM’s planned retirement of SJGS in 2022. PNM cannot predict the full impact of the ETA or the outcome of its potential future generating resource abandonment filings with the NMPRC.

International Accords

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

On December 12, 2015, the Paris Agreement was finalized during the 2015 COP. The aim of the Paris Agreement is to limit global temperature rise to two degrees Celsius above pre-industrial levels. The agreement, which was agreed to by 197 parties, requires that countries submit Intended Nationally Determined Contributions (“INDCs”). INDCs 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 INDC 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 INDC and is based on EPA’s final GHG regulations for new, existing, and modified and reconstructed sources. The United States is one of several nations that offered INDCs.  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.  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.” The United States continues to hold the position that it will withdraw from the Paris Agreement unless it can negotiate better terms. The earliest date that the United States could give formal notification of its withdrawal is November 4, 2020. In the interim, the United States continues to participate in international climate negotiations. It is uncertain if the United States will choose to pursue a transition to a low-carbon economy using a pathway that aligns with the Paris Agreement to keep global temperature rise to below two degrees Celsius (the “2 Degree Scenario”) above pre-industrial levels or in connection with other regulation or legislation. PNM has not conducted a 2 Degree Scenario analysis

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but is participating in the Electric Power Research Institute program, “Understanding Climate Change Scenarios and Goal-setting Activities”. PNM has also calculated GHG reductions that would result from implementation of the 2017 IRP scenarios that assume PNM would retire its share of the SJGS in 2022 and would exit from Four Corners in 2031. In addition, as an investor-owned utility operating in the state of New Mexico, PNM will be required to comply with the recently enacted ETA, which requires utilities’ generating portfolio be 100% carbon-free by 2045. As discussed above, PNM has set a goal to have a 100% emissions-free generating portfolio by 2040. The requirements of the ETA and the Company’s goal compare favorably to the 26% - 28% by 2025 United States INDC and the former administration’s effort to achieve an 80% reduction in carbon emissions by 2050. As discussed in Note 16, 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.

PNM will continue to monitor the United States’ and other parties’ 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 11.  While PNM currently expects the planned retirement of SJGS in 2022 (subject to NMPRC approval) will provide savings to customers, the ultimate consequences of climate change and environmental regulation 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 the long-term financial impact.

Transmission Issues

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

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

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

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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 11 and 12 herein and Notes 16 and 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K 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 Company management to select and apply accounting policies that best provide the framework to report the results of operations and financial position for PNMR, PNM, and TNMP. The selection and application of those policies requires management to make difficult, subjective, and/or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

As of March 31, 2019, there have been no significant changes with regard to the critical accounting policies disclosed in PNMR’s, PNM’s, and TNMP’s 2018 Annual Reports on Forms 10-K. The policies disclosed included regulatory accounting, impairments, decommissioning and reclamation costs, pension and other postretirement benefits, accounting for contingencies, and income taxes.

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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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, the appeal of that order, the NM 2016 Rate Case and related deferral of the issue of the prudence of PNM’s decision to continue participation in Four Corners to PNM’s next general rate case and recovery of PNM’s investments in that plant, any actions resulting from PNM’s December 2018 Compliance Filing, which indicates PNM intends to retire its share of SJGS in 2022 (subject to future NMPRC approval), including the impacts of the recently signed ETA, and/or the conclusions reached in PNM’s 2017 IRP (collectively, the “Regulatory Proceedings”) 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 of the Regulatory Proceedings and supporting forecasts utilized in future test year rate proceedings

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

• 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, the outcome of PNM’s December 2018 Compliance Filing, including the impacts of the recently signed ETA, the results of PNM’s 2017 IRP filing, which indicates that PNM’s customers would benefit from PNM’s exit from Four Corners in 2031, including regulatory recovery of undepreciated investments in the event the NMPRC orders generating facilities be retired

• 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 ultimate outcomes of the Regulatory 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, advances in technology, and other changes in supply and demand

• 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 outcomes of the Regulatory Proceedings

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

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

• The performance of generating units, transmission systems, and distribution systems, which could be negatively affected by operational issues, fuel quality and supply issues, unplanned outages, extreme weather conditions, wildfires, terrorism, cybersecurity breaches, and other catastrophic events, as well the costs the Company may incur to repair its facilities and/or the liabilities the Company may incur to third parties in connection with such issues

• State and federal regulation or legislation relating to environmental matters and renewable energy requirements, 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, and taxes, including pending guidance related to the Tax Act, 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, including the impacts of the recently signed ETA

• 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

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

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• 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

• Uncertainty surrounding counterparty performance and credit risk, including the ability of counterparties to supply fuel and perform reclamation activities and impacts to financial support provided to facilitate the coal supply at SJGS

• 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

Any material changes to risk factors occurring after the filing of PNMR’s, PNM’s, and TNMP’s 2018 Annual Reports on Form 10-K are disclosed in Item 1A, Risk Factors, in Part II of this Form 10-Q.

For information about the risks associated with the use of derivative financial instruments, see Item 3. “Quantitative and Qualitative Disclosures About Market Risk.”

SECURITIES ACT DISCLAIMER

Certain securities described or cross-referenced 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-Q does not constitute an offer to sell or the solicitation of an offer to buy any securities.

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, and outlines PNM’s plans (subject to NMPRC approval) to exit all coal-fired generation by 2031, reach 70% emissions-free generation by 2032, and reach 100% emissions-free generation by 2040.

The contents of these websites are not a part of this Form 10-Q. 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. 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.

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ITEM 3. 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 Risk Management Committee (“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 7, including a summary of the fair values of mark-to-market energy related derivative contracts included in the Condensed Consolidated Balance Sheets. During the three months ended March 31, 2019 and the year ended December 31, 2018, 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 Condensed Consolidated Balance Sheets. The following table details the changes in the net asset or liability balance sheet position for mark-to-market energy transactions.

	Three Months Ended
	March 31,
	2019			2018
Economic Hedges	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	(94	)	$	(94	)
Amount realized on contracts delivered during period	28			26
Changes in fair value	—			2
Net mark-to-market change recorded in earnings	28			28
Net change recorded as regulatory assets and liabilities	2			(175		)
Net fair value at end of period	$	(64	)	$	(241	)

All of the fair values as of March 31, 2019 were determined based on prices provided by external sources other than actively quoted market prices. The net mark-to-market amounts will settle in 2019.

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.

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.

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Schedule of Credit Risk Exposure
March 31, 2019
Rating(1)	Credit Risk Exposure(2)		Number of Counter-parties >10%	Net Exposure of Counter-parties >10%
	(Dollars in thousands)
External ratings:
Investment grade	$	2,644	1	$	773
Non-investment grade	—		—	—
Split ratings	—		—	—
Internal ratings:
Investment grade	2,100		3	1,755
Non-investment grade	—		—	—
Total	$	4,744		$	2,528

⁽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 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 March 31, 2019, PNMR held $0.9 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of March 31, 2019 was $0.8 million.

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 PNMR’s consolidated long-term debt instruments would increase by 2.4%, or $72.6 million if interest rates were to decline by 50 basis points from their levels at March 31, 2019. 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 May 3, 2019, PNMR, PNM, TNMP, and PNMR Development had short-term debt outstanding of $55.9 million, zero, $29.2 million, and $15.1 million under their revolving credit facilities, which allow for a maximum aggregate borrowing capacity of $300.0 million for PNMR, $400.0 million for PNM, $75.0 million for TNMP, and $25.0 million for PNMR Development. PNM had no borrowings under the $40.0 million PNM 2017 New Mexico Credit Facility at May 3, 2019. The revolving credit facilities, the PNM 2017 New Mexico Credit Facility, the $150.0 million PNMR 2018 One-Year Term Loan, the $50.0 million PNMR 2018 Two-Year Term Loan, the $90.0 million PNMR Development Term Loan, the $250.0 million PNM 2019 Term Loan, and the $35.0 million TNMP 2018 Term Loan bear interest at variable rates. On May 3, 2019, interest rates on borrowings averaged 3.73% for the PNMR Revolving Credit Facility, 3.23% for the PNMR 2018 One-Year Term Loan, 3.29% for the PNMR 2018 Two-Year Term Loan, 3.28% for the PNMR Development Term Loan, 3.14% for the PNM 2019 Term Loan, 3.23% for the TNMP Revolving Credit Facility, 3.18% for the TNMP 2018 Term Loan, and 3.48% for the PNMR Development 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 9, PNMR has entered into hedging arrangements to effectively establish fixed interest rates on $150.0 million of variable rate debt.

The investments held by PNM in trusts for decommissioning and reclamation had an estimated fair value of $351.6 million at March 31, 2019, of which 62.1% 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 March 31, 2019, the decrease in the fair value of the fixed-rate securities would be 2.9%, or $6.3 million.

PNM does not directly recover or return through rates any losses or gains on the securities, including equity investments discussed below, in the trusts for decommissioning and reclamation. 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 12, 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 is at risk for shortfalls in funding of obligations due to investment losses, including those from the equity market 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 include certain equity securities at March 31, 2019. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 34.9% of the securities held by the trusts as of March 31, 2019. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $12.3 million.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

As of the end of the period covered by this quarterly report, each of PNMR, PNM, and TNMP conducted an evaluation, under the supervision and with the participation of its management, including its Chief Executive Officer and 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 of each of PNMR, PNM, and TNMP concluded that the disclosure controls and procedures are effective.

Changes in internal controls over financial reporting

There have been no changes in each of PNMR’s, PNM’s, and 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 March 31, 2019 that have materially affected, or are reasonably likely to materially affect, each of PNMR’s, PNM’s, and TNMP’s internal control over financial reporting. PNMR, PNM, and TNMP adopted ASU 2016-02 – Leases (“ASC 842”) effective January 1, 2019. The Company updated certain policies and procedures and implemented a new software system related to the adoption of the new standard. However, the adoption of this standard did not result in significant changes to PNMR’s, PNM’s, and TNMP’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Notes 11 and 12 for information related to the following matters, for PNMR, PNM, and TNMP, incorporated in this item by reference.

Note 11

• The Energy Transition Act

• The Clean Air Act – Regional Haze – NEE Complaint

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

• Navajo Nation Environmental Issues

• Santa Fe Generating Station

• Continuous Highwall Mining Royalty Rate

• PVNGS Water Supply Litigation

• San Juan River Adjudication

• Rights-of-Way Matter

• Navajo Nations Allottee Matters

Note 12

• PNM – New Mexico General Rate Cases

• PNM – Renewable Portfolio Standard

• PNM – Energy Efficiency and Load Management – Petition for Energy Efficiency Disincentives

• PNM – Integrated Resource Plans

• PNM – San Juan Generating Station Unit 1 Outage

• PNM – Cost Recovery Related to Joining the EIM

• PNM – Facebook, Inc. Data Center Project

• PNM – Application For a New 345 KV Transmission Line

• TNMP – TNMP 2018 Rate Case

• TNMP – Order Related to Changes in Federal Income Tax Rates

• TNMP – Energy Efficiency

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ITEM 1A. RISK FACTORS

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in PNMR’s, PNM’s, and TNMP’s Annual Reports on Form 10-K for the year ended December 31, 2018.

ITEM 6. EXHIBITS

3.1	PNMR	Articles of Incorporation of PNMR, as amended to date (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed November 21, 2008)
3.2	PNM	Restated Articles of Incorporation of PNM, as amended through May 31, 2002 (incorporated by reference to Exhibit 3.1.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)
3.3	TNMP	Articles of Incorporation of TNMP, as amended through July 7, 2005 (incorporated by reference to Exhibit 3.1.2 to TNMP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
3.4	PNMR	Bylaws of PNMR, with all amendments to and including October 24, 2017 (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed October 25, 2017)
3.5	PNM	Bylaws of PNM, with all amendments to and including May 31, 2002 (incorporated by reference to Exhibit 3.1.2 to PNM’s Report on Form 10-Q for the fiscal quarter ended June 30, 2002)
3.6	TNMP	Bylaws of TNMP, with all amendments to and including June 18, 2013 (incorporated by reference to Exhibit 3.6 to TNMP’s Current Report on Form 8-K filed June 20, 2013)
4.1	TNMP	Tenth Supplemental Indenture dated March 29, 2019 between TNMP and MUFG Union Bank, N.A., as trustee (filed as Exhibit 4.1 to TNMP’s Current Report on Form 8-K filed March 29, 2019)
10.1	PNMR	PNMR 2019 Officer Annual Incentive Plan dated March 28, 2019
10.2	PNMR	PNMR 2019 Long-Term Incentive Plan dated March 28, 2019
10.3	PNMR	PNMR First Amendment to PNMR 2016 Long-Term Incentive Plan dated February 27, 2019
10.4	PNMR	PNMR First Amendment to PNMR 2017 Long-Term Incentive Plan dated February 27, 2019
10.5	PNMR	Discretionary Credit Award Agreement between PNMR and Charles N. Eldred effective February 21, 2019
10.6	TNMP	TNMP First Amendment to Third Amended and Restated Credit Agreement dated April 19, 2019 among TNMP, the lenders party thereto, and KeyBank National Association, as administrative agent
10.7	PNMR	Form of First Amendment to the PNMR Indemnity Agreement executed in March 2019 by PNMR officers
10.8	PNM	Term Loan Agreement entered into January 18, 2019 among PNM, the lenders party thereto and U.S. Bank National Association, as administrative agent (filed as Exhibit 10.1 to PNM’s Current Report on Form 8-K filed January 18, 2019)
10.9	TNMP	Bond Purchase Agreement dated February 26, 2019 between TNMP and the purchasers named therein (filed as Exhibit 10.3 to PNM’s Annual Report on Form 10-K for the year ended December 31, 2018)
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 Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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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, PNM, and TNMP	XBRL Instance Document
101.SCH	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Schema Document
101.CAL	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

		PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO TEXAS-NEW MEXICO POWER COMPANY
		(Registrants)
Date:	May 7, 2019	/s/ Joseph D. Tarry
		Joseph D. Tarry
		Vice President, Controller and Treasurer
		(Officer duly authorized to sign this report)

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EX-10.1

Exhibit 10.1

PNM RESOURCES, INC.

2019 OFFICER ANNUAL INCENTIVE PLAN

Introduction

PNM Resources, Inc. (the “Company” or “PNMR”) has adopted this 2019 Officer Annual Incentive Plan (the “Plan”) for the purpose of providing annual cash-based incentive awards (each an “Award”) to eligible Officers (as defined below). The Awards payable to Officers under the Plan are intended to qualify as Performance Cash Awards granted pursuant to Section 7.2 of the PNM Resources, Inc. 2014 Performance Equity Plan (the “PEP”). For the avoidance of doubt, the Awards are not intended to qualify as Performance-Based Awards granted pursuant to Section 10 of the PEP.

Capitalized terms used in the PEP and not otherwise defined in this Plan document have the meanings given to them in the PEP.

Eligibility

All Officers of the Company are eligible to participate in the Plan. For purposes of the Plan, the term “Officer” means any employee who (1) has the title of Chief Executive Officer, Executive Vice President, Senior Vice President or Vice President and (2) who is in salary grade H18 or higher.

Award Determinations in General

Awards are based on the Incentive Earnings Per Share (“Incentive EPS”) levels for the Performance Period as described below and as set forth in Table 1 of Attachment A, the weighting between Corporate and Business Area Goals as described in Table 2 of Attachment A and Award levels achieved during the Performance Period as described in Table 3 of Attachment A. The Performance Period began on January 1, 2019 and will end on December 31, 2019.

An Officer’s Award will equal the Officer’s share of the Incentive EPS Award Pool described below. If, however, the Officer’s share of the appropriate Performance Award Pool described below is less than the Officer’s share of the Incentive EPS Award Pool, the Officer will receive the smaller amount.

An Officer’s share of the Incentive EPS Award Pool or the Performance Award Pool (each, an “Award Pool”), as applicable, will be based upon the amount potentially payable to the Officer for the attained level of performance (Threshold, Target or Maximum), as determined in accordance with Table 3 of Attachment A, as compared to the aggregate amounts potentially payable for the attained level of performance to all of the Officers who are entitled to share in that Award Pool. In determining the amount potentially payable to an Officer, the base salaries will be determined as of December 31, 2019. In no event will the amount payable to an Officer exceed the indicated percentage of the Officer’s base salary for the attained performance level as

set forth in Table 3 of Attachment A. In addition, in no event will the amount payable to one Officer be increased due to a decrease in the amount payable to any other Officer.

Incentive EPS Award Pool

In order for any Awards to be payable to eligible Officers, the Company must achieve the Threshold Incentive EPS level set forth in Table 1 of Attachment A. If the Company does not achieve the Threshold Incentive EPS level (calculated before any charges for amounts due pursuant to this Plan), no Awards are payable under the Plan to any Officer. If the Company achieves the Threshold Incentive EPS level (calculated before any charges for amounts due pursuant to this Plan), but the charges for amounts due pursuant to this Plan reduce the Incentive EPS to an amount below the Threshold Incentive EPS level, the Threshold level Incentive EPS Award Pool shall be reduced by the amount necessary to assure that the Incentive EPS is equal to the Threshold Incentive EPS level, unless the Committee, in the exercise of its discretion concludes that no Awards should be payable.

If the Threshold, Target or Maximum Incentive EPS levels, as listed in Table 1 of Attachment A, are achieved, the aggregate potential Awards payable to the Officers at that level of performance (e.g., the aggregate level of Awards payable at Threshold, Target or Maximum as shown in Table 3 of Attachment A) will make up the “Incentive EPS Award Pool.” If the actual Incentive EPS exceeds the minimum level for a performance level by at least $0.01, but is less than the maximum level for that performance level (e.g., if the actual Incentive EPS exceeds $2.08 but is less than $2.11), the Incentive EPS Award Pool will be increased by using straight-line interpolation between the size of the Incentive EPS Award Pool based on the attained level (e.g., Threshold) and the size of the Incentive EPS Award Pool at the next higher level (e.g., Target). The Committee has the discretion to increase the Incentive EPS Award Pool by an amount less than the amount determined by using straight-line interpolation. The Incentive EPS Award Pool is capped by the aggregate Maximum Awards shown in Table 3 of Attachment A for all eligible Officers.

Performance Award Pool

A Corporate Goals Scorecard and Business Area Goals Scorecard listing each performance measure established by the Committee will be maintained by the PNMR Services Company Human Resources Department. As set forth in Table 2 of Attachment A, the performance of the Chief Executive Officer and the Senior Officers (the Executive Vice President and the Senior Vice Presidents) are measured 100% on the Corporate Goals Scorecard. Vice Presidents are measured 60% on the Corporate Goals Scorecard and 40% on the Business Area Goals Scorecard.

The “Performance Award Pool” for each Business Area is the amount that could be paid in the aggregate to the Vice Presidents assigned to that Business Area based on performance alone, determined by using the following multi-step process:

a) Select the scorecard results from the appropriate Corporate Goals Scorecard and Business Area Goals Scorecard;

b) Then multiply each result by the appropriate weighting for the scorecard as set forth in Table 2 of Attachment A;

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c) Then multiply the total Vice President salaries for that Business Area by the Target Award Level as set forth in Table 3 of Attachment A;

d) Then multiply the result of each scorecard (Step b), expressed as a percentage of Target, by the aggregate base salaries of the Vice Presidents included in that Business Area (Step c); and

e) Sum the results for the Vice President participants.

The Performance Award Pool for the Chief Executive Officer and the Senior Officers will be constructed by using the same process but will be based solely upon the Corporate Goals Scorecard.

Award Approval and Payout Timing

In early 2020, management will review the level of Awards, if any, and will provide the final Awards calculation to the Committee. The Committee will review the level of Awards and the Awards calculation and will approve the Awards for all Officers, other than the Chief Executive Officer. The independent directors of the Board will approve the Chief Executive Officer’s Award. To the extent Awards are payable under the Plan, the Company will make the payment on or before March 15, 2020 in a single lump sum cash payment, subject to applicable withholding.

The Committee shall retain the authority to adjust the Incentive EPS Award Pool and the Performance Award Pool, to adjust the level of attainment of the Incentive EPS or Corporate Goals and Business Area Goals Scorecards or to otherwise increase or decrease the amount payable with respect to any Award made pursuant to this Plan.

Provisions for a Change in Control

If a Change in Control occurs during the Performance Period and the Officer remains employed by the Company or an Affiliate at the end of the Performance Period, the Officer may be entitled to receive an Award for the Performance Period as determined in accordance with the provisions of this Plan. If the Plan is modified after the occurrence of a Change in Control in a manner that has the effect of reducing the amounts otherwise payable under the Plan, an Officer who remains employed by the Company or an Affiliate at the end of the Performance Period will receive, at a minimum, an Award equal to 50% of the Maximum Award available under this Plan for the Performance Period.

If an Officer terminates employment with the Company or an Affiliate during the Performance Period due to a Qualifying Change in Control Termination, the Officer may be entitled to receive a special payment pursuant to the PNM Resources, Inc. Officer Retention Plan in lieu of any payments under this Plan.

Pro-rata Awards for Partial Service Periods

In certain circumstances (as set forth below) Officers may or may not be eligible for a pro-rata Award under the Plan.

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The following Officers are not eligible for any Award, including a pro-rata Award:

– Officers who terminate employment with the Company or an Affiliate on or before the date on which Awards are distributed for the Performance Period for any reason other than death, Impaction (as defined in the PNM Resources, Inc. Non-Union Severance Pay Plan), Retirement or Disability. As noted above, Officers who terminate employment with the Company or an Affiliate during the Performance Period due to a Qualifying Change in Control Termination may be entitled to receive a special payment pursuant to the PNM Resources, Inc. Officer Retention Plan in lieu of any payments under this Plan.

– Officers who elect voluntary separation or Retirement in lieu of termination for performance or misconduct.

The following Officers may be eligible for a pro-rata Award:

– Officers who are newly hired during the Performance Period and are employed by the Company or an Affiliate on the day on which Awards are distributed for the Performance Period.

– Employees or Officers who are promoted, transferred or demoted during the Performance Period and are employed by the Company or an Affiliate on the day on which Awards are distributed for the Performance Period.

– Officers who are on leave of absence for any full month(s) during the Performance Period and are employed by the Company or an Affiliate on the day on which Awards are distributed for the Performance Period.

– Officers who terminate employment with the Company or an Affiliate during the Performance Period due to Impaction (as defined in the PNM Resources, Inc. Non-Union Severance Pay Plan), Retirement or Disability.

– Officers who die during the Performance Period, in which case the Award will be paid to the spouse of a married Officer or the estate of an unmarried Officer.

If an Officer is eligible for a pro-rata Award, it will be calculated based on the number of full month(s) that the Officer was actively employed at each eligibility level during the Performance Period compared to the number of full months included in the Performance Period. (Note: Only months in which the Officer is actively employed on the payroll on the first and last day of the month will count as a full month.) If an Officer who is eligible for a pro-rata Award is not employed on December 31, 2019, the pro-rata Award for the eligible Officer will be calculated using the Officer’s base salary on the date of his termination of employment. Any pro-rata Award to which an Officer becomes eligible pursuant to this paragraph will be paid to the Officer in a single lump sum cash payment subject to applicable withholding, on or before March 15, 2020.

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Ethics

The purpose of the Plan is to fairly reward performance achievement. Any Officer who manipulates or attempts to manipulate the Plan for personal gain at the expense of customers, shareholders, other employees or the Company or its Affiliates will be subject to disciplinary action, up to and including termination of employment, and will forfeit and be ineligible to receive any Award under the Plan.

Continuation of Employment

This Plan does not confer upon any Officer any right to continue in the employment of the Company or any Affiliate and does not limit the right of the Company or any Affiliate, in its sole discretion, to terminate the employment of any Officer at any time. This Plan also does not limit any right that the Company or any Affiliate has to terminate the employment of any Officer in accordance with any written employment agreement the Company and Officer may have.

Clawbacks

All Awards issued under this Plan are subject to potential forfeiture or recovery to the fullest extent called for by the Company’s Clawback Policy. By accepting an Award, an Officer consents to the Clawback Policy and agrees to be bound by and comply with the Clawback Policy and to return the full amount required by the Clawback Policy.

Amendments

The Committee, in its sole discretion, reserves the right to adjust, amend or suspend the Plan during the Performance Period. The Senior Vice President and General Counsel is hereby authorized to correct any typographical or similar errors in the Plan and any other documents issued in connection with the Plan.

/s/ Patrick V. Apodaca            

Patrick V. Apodaca

SVP and General Counsel

Dated: March28, 2019

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ATTACHMENT A

Incentive EPS Table

(Table 1)

	Incentive EPS1
No Award	Less than $2.08
Threshold	Greater than or equal to $2.08 and less than $2.11
Target	Greater than or equal to $2.11 and less than $2.18
Maximum	Greater than or equal to $2.18

Scorecard Weighting Table

(Table 2)

Scorecard Results
Scorecard Level	Corporate Weighting	Business Area Weighting
CEO & Senior Officers	100%	0%
Vice Presidents	60%	40%

Award Levels Table

(Table 3)

Award Levels	Threshold	Target	Maximum
CEO	57.5%	115%	230%
EVP	37.5%	75%	150%
SVP	27.5%	55%	110%
Vice-Presidents	20%	40%	80%

_________________________

¹Equals PNMR’s diluted EPS for the fiscal year ending December 31, 2019 calculated in accordance with Generally Accepted Accounting Principles and reported in the Company’s Form 10-K for PNMR adjusted to exclude the following items: (1) mark-to-market impact of economic hedges, (2) regulatory disallowances, (3) net change in unrealized gains and losses on investment securities, (4) gains or losses on reacquired debt, (5) goodwill or other asset impairments, (6) impacts of acquisition and disposition activities, including but not limited to pension expense or income associated with Public Service Company of New Mexico’s (“PNM”) former gas utility operations, (7) impact of the Company’s adoption of an accounting pronouncement or the Company’s adoption of a change in accounting pronouncement on or after February 22, 2019, (8) the loss, impairment, or write-up of any deferred tax asset or liability that was earned and recognized in a prior tax year, but that must be revalued in the current year, (9) judgments entered or settlements reached in litigation or other regulatory proceedings, (10) increases or decreases in the liabilities associated with PNM’s retired generating stations, including but not limited to expenses incurred in demolition or environmental work of such generating stations, (11) costs associated with process improvement initiatives, and (12) changes to the liabilities associated with mine reclamation costs including but not limited to (a) changes in the discount rate used to measure those liabilities, (b) an early retirement of generating stations or (c) actions taken by the New Mexico Public Regulation Commission.

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EX-10.2

Exhibit 10.2

PNM RESOURCES, INC.
2019 LONG-TERM INCENTIVE PLAN

Introduction

• The 2019 Long-Term Incentive Plan (the “Plan” or the “2019 Plan”) provides eligible Officers of PNM Resources, Inc. (the “Company” or “PNMR”) with the opportunity to earn Performance Share Awards (70% of the total opportunity) and time-vested Restricted Stock Rights Awards (30% of the total opportunity). For purposes of the Plan, “Officer” means any Officer of the Company who (1) has the title of Chief Executive Officer, Executive Vice President, Senior Vice President or Vice President and (2) who is in salary grade H18 or higher.

• The number of Performance Shares earned by an Officer for the Performance Period (as described below) will depend on the Officer’s position (e.g., Chief Executive Officer, Executive Vice President, Senior Vice President or Vice President) and base salary and the Company’s level of attainment of (1) an Earnings Growth Goal, (2) a Relative TSR Goal and (3) an FFO/Debt Ratio Goal, as described below and in Attachment A.

• The number of time-vested Restricted Stock Rights granted to an Officer at the end of each Performance Period will depend on the Officer’s position, the Officer’s base salary and the discretion of the Committee.

Performance Period

• The Performance Period began on January 1, 2019 and will end on December 31, 2021.

Performance Goals

• The number of Performance Shares that an Officer will receive for the Performance Period will depend on the Company’s level of attainment of an Earnings Growth Goal, a Relative TSR Goal and a FFO/Debt Ratio Goal.

• These goals and the corresponding Awards are described in the Performance Goal Table (Attachment A).

Performance Share Award Opportunities

• The Company’s level of attainment (Threshold, Target or Maximum) of the Earnings Growth Goal, Relative TSR Goal and the FFO/Debt Ratio Goal determines the level of the Officer’s Performance Share Awards.

• An Officer’s Performance Share Award opportunities also will vary depending on the Officer’s position and the Officer’s base salary, all as determined in accordance with the Performance Share Award Opportunity Table (Attachment B).

• For purposes of determining the number of Performance Shares to which an Officer is entitled at any particular Award level, the value of one Performance Share shall be equal to the Fair Market Value of one share of the Company’s Stock on the relevant Grant Date and the Officer’s base salary shall equal the Officer’s base salary as of the first day of the Performance Period.

Time-Vested Restricted Stock Rights Award Opportunities

• After the Performance Period (generally between the next following January 1 and March 15), the Committee will consider whether to grant time-vested Restricted Stock Rights Awards to the participating Officers.

• If the Committee, with the approval of the Board, decides to make a time-vested Restricted Stock Rights Award to a particular Officer, it must adopt a written resolution to that effect. In the resolution, the Committee will establish the Grant Date for the time-vested Restricted Stock Rights Award.

• An Officer’s time-vested Restricted Stock Rights Award opportunity will vary depending on the Officer’s position and the Officer’s base salary, all as determined in accordance with the attached Time-Vested Restricted Stock Rights Award Opportunity Table (Attachment C). The Committee reserves the discretion to grant an Award that is less than the opportunity set forth in the Table or to grant no time-vested Restricted Stock Rights Award to a particular Officer.

• For purposes of determining the number of time-vested Restricted Stock Rights to which an Officer will be entitled, the value of one time-vested Restricted Stock Right shall be equal to the Fair Market Value of one share of the Company’s Stock on the Grant Date specified in the Committee’s resolution and the Officer’s base salary shall equal the Officer’s base salary on the Grant Date.

Other Provisions

• All of the Awards will be made pursuant to the PNM Resources, Inc. 2014 Performance Equity Plan, as amended (the “PEP”) or any successor to the PEP. Any references in the Plan to the PEP shall be deemed to be a reference to the corresponding provisions of any successor to the PEP.

• All of the Awards will be subject to the standard Terms and Conditions attached hereto as Attachment D.

• The Grant Date for the Performance Share Awards is March 4, 2019 (the first trading day after expiration of the current black-out period, as determined in accordance with the Company’s Equity Compensation Awards Policy).

• A prorated Performance Share Award will be provided to an Officer who has a Separation from Service in the second half of the Performance Period (in other words, between July 1, 2020 and December 31, 2021) due to death, Disability, Retirement or Impaction. A prorated Award will not be paid to an Officer who incurs a Separation from Service for any of these reasons during the first half of the Performance Period or to an Officer who incurs a Separation from Service for any other reason other than a Qualifying Change in Control Termination prior to the last day of the Performance Period.

• The prorated Award will be calculated at the end of the Performance Period based on actual performance during the Performance Period. The proration will be made based on the number of full months of service completed by the Officer during the Performance Period, using the proration rules described in Section 11.1(a)(iv)(2) of

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the PEP. The prorated Award then will be paid at the same time as Awards are paid to other participants in the Plan.

• Notwithstanding any provision in the Plan to the contrary, Company’s Executive Vice President and Chief Financial Officer (determined as of the first day of the Performance Period) shall be entitled to a full (rather than a prorated) Performance Share Award, calculated at the end of the Performance Period based on actual performance during the Performance Period, if he has a Separation from Service at any time during the Performance Period for reasons other than for Cause.

• Upon an Officer’s Separation from Service due to a Qualifying Change in Control Termination, a prorated portion of the Performance Shares will vest at the end of the Performance Period based on the level of achievement of the performance goals in accordance with the applicable provisions of the PEP.

• If an individual ceases to be an Officer during a Performance Period but remains employed by the Company or its Affiliates, the Committee may grant a prorated Performance Share Award to the former Officer on such terms and conditions as the Committee deems to be appropriate as long as the individual was an Officer for at least half of the Performance Period.

• If an individual becomes an Officer during a Performance Period, the Committee may grant a prorated Performance Share Award to the new Officer on such terms and conditions as the Committee deems to be appropriate.

• For the avoidance of doubt, the Performance Share Awards are not intended to qualify as Performance-Based Awards granted pursuant to Section 10 of the PEP. As a result, such Awards are not subject to the requirements of Section 10 of the PEP.

• All Awards issued under this Plan are subject to potential forfeiture or recovery to the fullest extent called for by the Company’s Clawback Policy. By accepting an Award, an Officer consents to the Clawback Policy and agrees to be bound by and comply with the Clawback Policy and to return the full amount required by the Clawback Policy.

/s/ Patrick V. Apodaca                

Patrick V. Apodaca

SVP and General Counsel

Dated: March28, 2019

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ATTACHMENT A

Performance Goal Table

Goal	Threshold Level1	Target Level1	Maximum Level1,2
Earnings Growth3 If the Company’s Earnings Growth on the last day of the Performance Period places it in the Threshold, Target or Maximum Level range for the Performance Period, the Officer will be entitled to receive 50% of the Threshold, Target or Maximum Award as determined in accordance with the Performance Share Award Opportunity Table.	At least 2%, but less than 3%	At least 3%, but less than 6%	At least 6%
Relative TSR4 If the Company’s Relative TSR for the Performance Period places it in the Threshold, Target or Maximum Level range shown to the right, the Officer will be entitled to receive 25% of the Threshold, Target or Maximum Award as determined in accordance with the Performance Share Award Opportunity Table.	Greater than or equal to the 35th percentile and less than the 50th percentile	Greater than or equal to the 50th percentile and less than the 90th percentile	Greater than or equal to the 90th percentile
FFO/Debt Ratio5 If the Company’s FFO/Debt Ratio on the last day of the Performance Period places it in the Threshold, Target or Maximum Level range for the Performance Period, the Officer will be entitled to receive 25% of the Threshold, Target or Maximum Award as determined in accordance with the Performance Share Award Opportunity Table.	At least 13%, but less than 14%	At least 14%, but less than 16%	At least 16%

__________________________

¹ If the Company’s Earnings Growth, Relative TSR or FFO/Debt Ratio falls between two Award levels (e.g., the Threshold Level and the Target Level shown in the Performance Goal Table), the number of Performance Shares to which an Officer is entitled will be interpolated between the two Award levels in accordance with uniform procedures prescribed by the Committee.

² In no event will an Officer receive more than the Maximum Award for an Officer of his or her level as listed in the Performance Share Award Opportunity Table.

³Earnings Growth, for the Performance Period, will be calculated by measuring the compounded annual growth rate by dividing the Earnings Per Share (as defined below) for the year ended December 31, 2021 by the Earnings Per Share (as defined below) for the year ended December 31, 2018. The resulting earnings growth multiple will

A-1

_____________________________________________________________________________________________

then be multiplied to the 1/3 power and subtract 1. The calculation would be as follows: [(2021 Earnings Per Share/2018 Earnings Per Share) ^ (1/3)] -1.

Earnings Per Share for the above calculation equals PNMR's diluted EPS for the fiscal years ending December 31, 2018 and 2021 calculated in accordance with Generally Accepted Accounting Principles and reported in the Company's Form 10-K for PNMR adjusted to exclude the following items: (1) mark-to-market impact of economic hedges, (2) regulatory disallowances, (3) net change in unrealized gains and losses on investment securities, (4) gains or losses on reacquired debt, (5) goodwill or other asset impairments, (6) impacts of acquisition and disposition activities, including but not limited to pension expense or income associated with Public Service Company of New Mexico's ("PNM") former gas utility operations, (7) impact of the Company's adoption of an accounting pronouncement or the Company's adoption of a change in accounting pronouncement on or after February 22, 2019, (8) the loss, impairment, or write-up of any deferred tax asset or liability that was earned and recognized in a prior tax year, but that must be revalued in the current year, (9) judgments entered or settlements reached in litigation or other regulatory proceedings, (10) increases or decreases in the liabilities associated with PNM's retired generating stations, including but not limited to expenses incurred in demolition or environmental work of such generating stations, (11) costs associated with process improvement initiatives, and (12) changes to the liabilities associated with mine reclamation costs including but not limited to (a) changes in the discount rate used to measure those liabilities, (b) an early retirement of generating stations or (c) actions taken by the New Mexico Public Regulation Commission.

⁴ The “Relative TSR” Goal refers to the Company’s “Total Shareholder Return” for the Performance Period as compared to the “Total Shareholder Return” of the other utilities included in the EEI Index.

For this purpose, the Total Shareholder Return of the Company and the other utilities included in the EEI Index will be determined by adding any dividends paid by the Company (or such other utilities) to the change in value of the Company’s Stock (or the other utilities’ common stock). The change in value shall be measured by comparing the “Beginning Stock Price” and “Ending Stock Price.” The “Beginning Stock Price” is the average closing price of the Company’s Stock (or the common stock of the other utilities) on the 20 trading days immediately preceding the first day of the Performance Period. The “Ending Stock Price” is the average closing price of the Company’s Stock (or the common stock of the other utilities) on the last 20 trading days of the Performance Period.

⁵ The FFO/Debt Goal equals PNMR's funds from operations for the fiscal year ending December 31, 2021, divided by PNMR's total debt outstanding (including any long-term leases and unfunded pension plan obligations) as of December 31, 2021. Funds from operations are equal to the amount of PNMR's net cash flow from operating activities (as reflected on the Consolidated Statement of Cash Flows) as reported in the Company's Form 10-K for PNMR adjusted by the following items: (1) including amounts attributable to principal payments on imputed debt from long-term leases, (2) excluding changes in PNMR's working capital, including bad debt expense, (3) excluding the impacts of any consolidation required by the Variable Interest Entities accounting rules and regulations, (4) subtracting the amount of capitalized interest, (5) excluding impacts on future material changes to the federal and state tax rate and (6) excluding any contributions to the PNMR or TNMP qualified pension plans. The calculation is intended to be consistent with Moody's calculation of FFO/Debt (which Moody's refers to as “CFO Pre-WC/Debt”) and includes any other adjustments to be consistent with Moody’s methodology as of February 22, 2019.

A-2

ATTACHMENT B

Performance Share Award Opportunity Table

Officer Level	Threshold Award	Target Award	Maximum Award
CEO	Performance Shares = 96.25% of base salary	Performance Shares = 192.5% of base salary	Performance Shares = 385% of base salary
EVP	Performance Shares = 52.5% of base salary	Performance Shares = 105% of base salary	Performance Shares = 210% of base salary
SVP	Performance Shares = 29.75% of base salary	Performance Shares = 59.5% of base salary	Performance Shares = 119% of base salary
VP	Performance Shares = 17.5% of base salary	Performance Shares = 35% of base salary	Performance Shares = 70% of base salary

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ATTACHMENT C

Time-Vested Restricted Stock Rights Award Opportunity Table

Officer Level	Award
CEO	Restricted Stock Rights = 82.5% of base salary
EVP	Restricted Stock Rights = 45% of base salary
SVP	Restricted Stock Rights = 25.5% of base salary
VP	Restricted Stock Rights = 15% of base salary

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ATTACHMENT D

2019 LONG-TERM INCENTIVE PLAN

TERMS AND CONDITIONS

PNM Resources, Inc. (the “Company” or “PNMR”) has adopted the PNM Resources, Inc. 2014 Performance Equity Plan, as amended (the “PEP”) or any successor to the PEP. Pursuant to the PEP, the Committee has developed the PNM Resources, Inc. 2019 Long-Term Incentive Plan (the “Plan” or the “2019 Plan”) pursuant to which eligible Officers may receive Performance Share Awards and time-vested Restricted Stock Rights Awards.

All of the Awards granted under the 2019 Plan are made pursuant to the PEP and are subject to the provisions of the PEP. In addition, all of the Awards under the 2019 Plan are made subject to these Terms and Conditions. All of the terms of the PEP are incorporated into this document by reference.

Capitalized terms used in but not otherwise defined in this document shall have the meanings given to them in the PEP. Any references in the Plan to the PEP shall be deemed to be a reference to the corresponding provisions of any successor to the PEP.

1.    Performance Share Awards.

(a)    Determination of Earnings Growth, Relative TSR and FFO/Debt Ratio. The Committee will determine the Earnings Growth, Relative TSR and the FFO/Debt Ratio for the Performance Period and the Officer’s corresponding Performance Share Award, if any, by March 15, 2022. The Committee then will submit its recommendations to the Board of Directors for review and approval. The Performance Shares to which an Officer is entitled shall become payable at the times described below.

(b)    Separation from Service; Forfeiture. Unless an Officer qualifies for a prorated Award as described in the Plan due to a Qualifying Change in Control Termination or as the result of the Officer’s Separation from Service during the second half of the Performance Period due to death, Disability, Retirement, or Impaction, the Officer’s Award will be forfeited upon the Officer’s Separation from Service prior to the end of the Performance Period. If the Company terminates an Officer’s employment for Cause during or following the expiration of the Performance Period, all vested and unvested Performance Shares shall be canceled and forfeited immediately, regardless of whether the Officer elects Retirement. As described in the Plan, the Company’s Executive Vice President and Chief Financial Officer (determined as of the first day of the Performance Period) shall be entitled to a full (rather than a prorated) Performance Share Award, calculated at the end of the Performance Period based on actual performance during the Performance Period, if he has a Separation from Service at any time during the Performance Period for reasons other than for Cause.

(c)    Form and Timing of Delivery of Stock. All of the Performance Shares awarded and vested pursuant to the Plan will be paid in Stock within the first 90 days of the calendar year following the end of the Performance Period. The Performance Shares granted under this Plan are subject to the requirements of Section 409A of the Code. Accordingly, the restrictions described in Section 18.3 of the PEP apply to the Performance Shares.

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2.    Time-Vested Restricted Stock Rights Awards.

(a)    Vesting.

(1)    Except as set forth below, the time-vested Restricted Stock Rights shall vest in the following manner: (i) 33% of the time-vested Restricted Stock Rights will vest on March 7, 2023; (ii) an additional 34% of the time-vested Restricted Stock Rights will vest on March 7, 2024; and (iii) the final 33% of the time-vested Restricted Stock Rights will vest on March 7, 2025 (each a “Vesting Date”).

(2)    Upon an Officer’s involuntary or voluntary Separation from Service for any reason other than those set forth in Section 2(a)(3), the time-vested Restricted Stock Rights, if not previously vested, shall be canceled and forfeited immediately.

(3)    Upon an Officer’s Separation from Service due to death, Disability, Retirement, Impaction or a Qualifying Change in Control Termination, any unvested time-vested Restricted Stock Rights shall become 100% vested in accordance with the applicable provisions of the PEP.

(b)    Form and Timing of Delivery of Certificate. All of the time-vested Restricted Stock Rights awarded pursuant to this Plan will be paid in Stock in accordance with the following provisions:

(1)    If any time-vested Restricted Stock Rights vest in accordance with Section 2(a)(1), the Officer will generally receive the Stock payable with respect to such vested time-vested Restricted Stock Rights within 90 days following each Vesting Date and in all cases by December 31 following the applicable Vesting Date.

(2)    If any time-vested Restricted Stock Rights vest in accordance with Section 2(a)(3), the Officer will receive the Stock payable with respect to such time-vested Restricted Stock Rights within 90 days following the date of the Officer’s Separation from Service.

(3)    If the 90‑day period during which payments may be made pursuant to Section 2(a)(1) or (3) begins in one calendar year and ends in another, the Officer will receive the Stock in the second calendar year.

(4)    All Stock will be awarded in accordance with the requirements of Section 409A of the Code and Section 18.3 of the PEP.

3.    Adjustments. Neither the existence of the Plan nor the Awards shall affect, in any way, the right or power of the Company to make or authorize: any or all adjustments, recapitalizations, reorganizations, or other changes in the Company’s capital structure or its business; or any merger or consolidation of the Company; or any corporate act or proceeding, whether of a similar character or otherwise; all of which, and the resulting adjustments in, or impact on, the Awards are more fully described in Section 4.3 of the PEP.

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4.    Dividend Equivalents. An Officer will not be entitled to receive a dividend equivalent for any of the Performance Shares or time-vested Restricted Stock Rights granted under the Plan.

5.    Withholding. The Company shall have the power to withhold, or require an Officer to remit to the Company, up to the maximum amount necessary to satisfy federal, state, and local tax withholding requirements in the applicable jurisdiction on any Award under the Plan, all in accordance with the provisions of the PEP.

6.    Securities Law Compliance. The delivery of the time-vested Restricted Stock Rights or earned Performance Shares may be delayed to the extent necessary to comply with Federal securities laws.

7.    Status of Plan and Administration. The Plan and these Terms and Conditions shall at all times be subject to the terms and conditions of the PEP and shall in all respects be administered by the Committee in accordance with the terms of and as provided in the PEP. The Committee shall have the sole and complete discretion with respect to the interpretation of the Plan, these Terms and Conditions and the PEP, and all matters reserved to it by the PEP. The decisions of the majority of the Committee shall be final and binding upon an Officer and the Company. In the event of any conflict between the terms and conditions of the Plan or these Terms and Conditions and the PEP, the provisions of the PEP shall control.

8.    Waiver and Modification. The provisions of the Plan and these Terms and Conditions may not be waived or modified unless such waiver or modification is in writing signed by an authorized representative of the Committee.

9.    Amendment or Suspension. The Committee, in its sole discretion, reserves the right to adjust, amend or suspend the Plan and these Terms and Conditions during the Performance Period except as otherwise provided in the PEP. The Senior Vice President and General Counsel is hereby authorized to correct any typographical or similar errors in the Plan, the Terms and Conditions and any other documents issued in connection with the Plan.

10.    Ethics. The purpose of the Plan is to fairly reward performance achievement. Any Officer who manipulates or attempts to manipulate the Plan for personal gain at the expense of customers, shareholders, other employees, or the Company or its Affiliates will be subject to disciplinary action, up to and including termination of employment, and will forfeit and be ineligible to receive any Award under the Plan.

D-3

EX-10.3

Exhibit 10.3

FIRST AMENDMENT

TO THE

PNM RESOURCES, INC.

2016 LONG-TERM INCENTIVE PLAN

The 2016 Long-Term Incentive Plan (the “Plan”) was adopted pursuant to the PNM Resources, Inc. 2014 Performance Equity Plan (the “PEP”). By this instrument, the Company desires to amend the Plan as set forth below.

1.    The definition of FFO/Debt Ratio as set forth in footnote 4 of the Plan is hereby amended and restated in its entirety to read as follows:

⁴ Equals PNMR’s funds from operations for the fiscal year ending December 31, 2018, divided by PNMR’s total debt outstanding (including any long-term leases and unfunded pension plan obligations and reducing debt by amount determined in (6) below) as of December 31, 2018. Funds from operations are equal to the amount of PNMR’s net cash flow from operating activities (as reflected on the Consolidated Statement of Cash Flows) as reported in the Company’s Form 10-K for PNM Resources adjusted by the following items: (1) including amounts attributable to principal payments on imputed debt from long-term leases, (2) excluding changes in PNMR’s working capital, including bad debt expense, (3) excluding the impacts of any consolidation required by the Variable Interest Entities accounting rules and regulations, (4) subtracting the amount of capitalized interest, (5) excluding any contributions to the PNMR or TNMP qualified pension plans, (6) excluding the change in revenues associated with the 2017 Tax Cuts and Jobs Act based on cost of service studies filed before regulatory bodies between the effective date of when those revenues were returned back to customers and December 31, 2018, and (7) by making the same adjustments associated with the Westmoreland transaction as Moody’s to calculate funds from operations or total debt outstanding for the fiscal year ending December 31, 2018. The calculation is intended to be consistent with Moody’s calculation of FFO/Debt (which Moody’s refers to as “CFO Pre-WC/Debt”) and if Moody’s modifies its calculation methodology prior to December 31, 2018 and communicates such changes in writing to Company representatives or the general public prior to December 31, 2018, the Moody’s calculation methodology in effect as of December 31, 2018 will be utilized.

2.    This First Amendment amends only the provisions of the Plan as noted above, and those provisions not expressly amended shall be considered in full force and effect. Notwithstanding the foregoing, this First Amendment shall superseded the provisions of the Plan to the extent those provisions are inconsistent with the provisions and intent of this First Amendment.

IN WITNESS WHEREOF, the Company has caused this First Amendment to be executed by its duly authorized representative on this 27th day of February, 2019.

PNM RESOURCES, INC.

By: /s/ Patrick V. Apodaca

Patrick V. Apodaca

Its: Senior Vice President, General Counsel

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EX-10.4

Exhibit 10.4

FIRST AMENDMENT

TO THE

PNM RESOURCES, INC.

2017 LONG-TERM INCENTIVE PLAN

The 2017 Long-Term Incentive Plan (the “Plan”) was adopted pursuant to the PNM Resources, Inc. 2014 Performance Equity Plan (the “PEP”). By this instrument, the Company desires to amend the Plan as set forth below.

1.    The definition of FFO/Debt Ratio as set forth in footnote 5 of the Plan is hereby amended and restated in its entirety to read as follows:

⁵ The FFO/Debt Goal equals PNMR’s funds from operations for the fiscal year ending December 31, 2019, divided by PNMR’s total debt outstanding (including any long-term leases and unfunded pension plan obligations and reducing debt by the sum of amount determined in (6) below) as of December 31, 2019 plus the amount excluded pursuant item (6) in the definition of FFO/Debt Ratio under the 2016 Long-Term Incentive Plan, as amended) as of December 31, 2019. Funds from operations are equal to the amount of PNMR’s net cash flow from operating activities (as reflected on the Consolidated Statement of Cash Flows) as reported in the Company’s Form 10-K for PNM Resources adjusted by the following items: (1) including amounts attributable to principal payments on imputed debt from long-term leases, (2) excluding changes in PNMR’s working capital, including bad debt expense, (3) excluding the impacts of any consolidation required by the Variable Interest Entities accounting rules and regulations, (4) subtracting the amount of capitalized interest, (5) excluding any contributions to the PNMR or TNMP qualified pension plans, and (6) excluding the change in revenues associated with the 2017 Tax Cuts and Jobs Act based on cost of service studies filed before regulatory bodies. The calculation is intended to be consistent with Moody’s calculation of FFO/Debt (which Moody’s refers to as “CFO Pre-WC/Debt”) and if Moody’s modifies its calculation methodology prior to December 31, 2019 and communicates such changes in writing to Company representatives or the general public prior to December 31, 2019, said changes in Moody’s methodology in effect as of December 31, 2019 will be incorporated into the calculation outlined above.

2.    This First Amendment amends only the provisions of the Plan as noted above, and those provisions not expressly amended shall be considered in full force and effect. Notwithstanding the foregoing, this First Amendment shall superseded the provisions of the Plan to the extent those provisions are inconsistent with the provisions and intent of this First Amendment.

IN WITNESS WHEREOF, the Company has caused this First Amendment to be executed by its duly authorized representative on this 27th day of February, 2019.

PNM RESOURCES, INC.

By: /s/ Patrick V. Apodaca

Patrick V. Apodaca

Its: Senior Vice President, General Counsel

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EX-10.5

Exhibit 10.5

DISCRETIONARY CREDIT AWARD AGREEMENT

Effective as of February 21, 2019, this Discretionary Credit Award Agreement (the “Agreement”) is entered into by and between PNM Resources, Inc. (“PNMR”) and Charles N. Eldred (“Employee”) (collectively, the “Parties”).

1.Purpose. Section 3.5 of the PNM Resources, Inc. Executive Savings Plan II (the “Plan”) permits the Compensation Committee and Human Resources Committee (the “Committee”) to allocate Discretionary Credits in such amounts and subject to such terms and conditions as the Committee deems appropriate. The purpose of this Agreement is to award a Discretionary Credit to Employee subject to the terms and conditions set forth below. Except as otherwise set forth in this document, the provisions of the Plan shall apply in determining the rights of Employee and the administration of Employee’s Discretionary Credit Account. Capitalized terms used in but not otherwise defined in this Agreement shall have the meanings given to them in the Plan. In cases of conflict, this Agreement controls over any conflicting provisions of Plan, except as may be required by Section 409A of the Code or the provisions of any other applicable law or regulation.

2.Discretionary Credit. PNMR shall allocate a Discretionary Credit equal to $434,137 to the Employee’s Discretionary Credit Account in the Plan as of December 31, 2019, provided Employee remains employed by the Company or its Affiliates on such date.

3.Termination of Employment.

(a)Termination by Company without Cause. Company may terminate Employee’s employment without “Cause” prior to December 31, 2019 (including following a Change in Control). For purposes of this Agreement, “Cause” shall have the meaning set forth in the PNM Resources, Inc. Officer Retention Plan. If Company terminates Employee’s employment without Cause pursuant to this Section, Employee will receive the Discretionary Credit described in Section 3, which shall be allocated to Employee’s Discretionary Credit Account as of the date of his termination of employment. In such instance, Employee also may be entitled to receive severance or retention benefits pursuant to the PNM Resources, Inc. Non-Union Severance Pay Plan or the PNM Resources, Inc. Officer Retention Plan if the requirements of the plans are met.

(b)Termination by Company for Cause. If Company terminates Employee’s employment for Cause prior to December 31, 2019, Employee will not be entitled to receive the Discretionary Credit provided for by this Agreement.

(c)Termination by Employee. If Employee terminates employment for any reason prior to December 31, 2019, Employee will not be entitled to receive the Discretionary Credit provided for by this Agreement.

4.     Disability. If Employee becomes Disabled prior to December 31, 2019, Employee will receive the Discretionary Credit described in Section 3, which shall be allocated to Employee’s Discretionary Credit Account as of the date of Employee’s Disability.

5.Death. If Employee dies prior to December 31, 2019, Employee will receive the Discretionary Credit described in Section 3, which shall be allocated to Employee’s Discretionary Credit Account as of the date of Employee’s death.

6.Payment of Discretionary Credit. The Discretionary Credit provided for by this Agreement shall be paid in the form of equal annual installments over five (5) years in accordance with the terms of the Plan. If Employee dies before the expiration of the installment period, the remaining installment distributions will be paid in a single lump sum payment to Employee’s designated beneficiary. Distribution of the Discretionary Credit will begin on the earliest of Employee’s Separation from Service, death or Disability. If Employee is a Specified Employee on the date of his Separation from Service, the payment of Employee’s Discretionary Credit shall not begin until the date which is six (6) months after the Employee’s Separation from Service in accordance with the terms of the Plan. Employee hereby agrees to the terms and provisions of the Plan. Employee does not have the right to select the time and form of payment of the Discretionary Credit.

7.Amendment or Waiver. No provision of this Agreement may be modified, waived or discharged unless such modification, waiver or discharge is agreed to in a writing signed by Employee and an authorized officer of PNMR.

8.Section 409A Compliance. This Agreement shall be administered in accordance with Section 409A or an exception thereto, and each provision of this Agreement shall be interpreted, to the extent possible, to comply with Section 409A or to qualify for an exception thereto. Although this Agreement has been designed to comply with Section 409A or to fit within an exception to the requirements of Section 409A, PNMR specifically does not warrant such compliance. Employee remains solely responsible for any adverse tax consequences imposed upon him by Section 409A.

9.Scope of Agreement; At Will Employment. All terms and conditions of Employee’s employment with PNMR Services Company (the “Company”) are unchanged and are determined pursuant to Company’s employment policies and practices unless otherwise specifically modified by this Agreement. Employee acknowledges that Employee’s employment by Company remains “at-will” and that Employee or Company may terminate the employment relationship at any time for any reason. If the employment relationship ends during the term of this Agreement, this Agreement will only govern the terms of the payment of the Discretionary Credit.

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IN WITNESS WHEREOF, PNMR and Employee have caused this Agreement to be executed as of the date set forth below.

PNM RESOURCES, INC

By: /s/ Patrick V. Apodaca

Patrick V. Apodaca

Its: Senior Vice President, General Counsel

EMPLOYEE

Charles N. Eldred

Employee’s Name (printed)

/s/ Charles N. Eldred

Employee’s Signature

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EX-10.6

Exhibit 10.6

EXECUTION COPY

FIRST AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT

THIS FIRST AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT (this "Amendment") is entered into as of April 19, 2019 among TEXAS-NEW MEXICO POWER COMPANY, a Texas corporation (the "Borrower"), the Lenders party hereto and KEYBANK, NATIONAL ASSOCIATION, as Administrative Agent for the Lenders (in such capacity, the "Administrative Agent"). Capitalized terms used herein and not otherwise defined shall have the meanings ascribed thereto in the Credit Agreement (as defined below).

R E C I T A L S

WHEREAS, the Borrower, the Lenders party thereto and the Administrative Agent are parties to that certain Third Amended and Restated Credit Agreement, dated as of September 25, 2017 (as amended or modified from time to time, the "Credit Agreement");

WHEREAS, the Borrower has requested a modification to the Credit Agreement as described below; and

WHEREAS, the Administrative Agent and the Lenders party hereto are willing to agree to such modification, subject to the terms set forth herein as more fully set forth below.

NOW, THEREFORE, in consideration of the premises and the mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto agree as follows:

A G R E E M E N T

1.    Amendments to Credit Agreement. Effective as of the date first written above and subject to the conditions set forth in Section 2 below, the Credit Agreement is hereby amended as follows:

(a)Section 1.1 of the Credit Agreement is amended to add the following definitions thereto in appropriate alphabetical order:

“Beneficial Ownership Certification” means a certification regarding beneficial ownership as required by the Beneficial Ownership Regulation.

“Beneficial Ownership Regulation” means 31 C.F.R. §1010.230.

“First Amendment Effective Date” means April 19, 2019.

(b)The definition of “Interest Payment Date” in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Interest Payment Date” means, (a) as to any Eurodollar Loan, the last day of each Interest Period applicable to such Loan, the date of any prepayment of the Loans pursuant to Section 3.3 and the Maturity Date; provided, however, that if any Interest Period for a Eurodollar Loan exceeds three months, the respective dates that fall every three months after the beginning of such Interest Period shall also be Interest Payment Dates, (b) as to any Base Rate Loan, the third

Business Day after the end of each Fiscal Quarter, the date of any prepayment of the Loans pursuant to Section 3.3 and the Maturity Date and (c) as to LIBOR Market Index Rate Swing Line Loans, the third Business Day after the end of each calendar month and the Maturity Date.

(c)The definition of “SEC Reports” in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“SEC Reports” means the Borrower’s Form 10-K Report for the year ended December 31, 2018.

(d)The definition of “Swing Line Sublimit” in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

“Swing Line Sublimit” means an amount equal to $15,000,000. The Swing Line Sublimit is part of, and not in addition to, the Revolving Committed Amount.

(e)Section 1 of the Credit Agreement is hereby amended by adding the following as Section 1.8 thereto:

1.8 Rates. The Administrative Agent does not warrant or accept responsibility for, and shall not have any liability with respect to, the administration, submission or any other matter related to the rates in the definition of “Eurodollar Rate”.

(f)Section 2.2(i) of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

(i)    Fronting Fee and Documentary and Processing Charges Payable to L/C Issuers. The Borrower shall pay directly to the applicable L/C Issuer for its own account a fronting fee with respect to each Letter of Credit in the amounts set forth in the applicable Fee Letter (the “L/C Fronting Fee”). The L/C Fronting Fee shall be computed on a quarterly basis in arrears and shall be due and payable on the third Business Day after the end of each Fiscal Quarter (as well as the Letter of Credit Expiration Date) for the Fiscal Quarter (or portion thereof) then ending, beginning with the first of such dates to occur after the issuance of such Letter of Credit. In addition, the Borrower shall pay directly to the applicable L/C Issuer for its own account the customary issuance, presentation, amendment and other processing fees, and other standard costs and charges, of such L/C Issuer relating to letters of credit as from time to time in effect. Such customary fees and standard costs and charges are due and payable on demand and are nonrefundable.

(g)Section 3.4(a) of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

(a)    Commitment Fees. In consideration of the Revolving Committed Amount being made available by the Lenders hereunder, the Borrower agrees to pay to the Administrative Agent, for the pro rata benefit of each Lender based on its Pro Rata Share, a per annum fee equal to the daily average sum of the Applicable Percentage for Commitment Fees for each day during the period of determination multiplied by the Unused Revolving Commitment for each such day (the “Commitment Fees”). The Commitment Fees shall commence to accrue on the Closing Date and shall be due and payable in arrears on the third Business Day after the end of each Fiscal Quarter (as well as on the Maturity Date and on any date that the Revolving Committed Amount is reduced) for the Fiscal Quarter (or portion thereof) then ending, beginning with the first of such dates to occur after the Closing Date. For purposes of clarification, Swing Line Loans shall

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not be considered usage of the Revolving Committed Amount for the purpose of calculating the Commitment Fees.

(h)Section 3.4(c) of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

(c)    L/C Fees. The Borrower shall pay to the Administrative Agent for the account of each Lender in accordance with its Pro Rata Share a fee for each Letter of Credit issued at its request at a rate per annum equal to the Applicable Percentage for L/C Fees times the daily maximum amount available to be drawn under such Letter of Credit (the “L/C Fees”). The L/C Fees shall be computed on a quarterly basis in arrears and shall be due and payable on the third Business Day after the end of each Fiscal Quarter (as well as on the Letter of Credit Expiration Date) for the Fiscal Quarter (or portion thereof) then ending, beginning with the first of such dates to occur after the issuance of such Letter of Credit.

(i)Section 3.10 of the Credit Agreement is hereby amended to add “(a)” before the first paragraph and adding the following as paragraph (b) thereto:

(b) In the event ICE Benchmark Administration Limited (or any Person that takes over the administration of such rate) discontinues its administration and publication of interest settlement rates for deposits in Dollars, as determined by the Administrative Agent (which determination shall be conclusive absent manifest error), then (i) the Administrative Agent and the Borrower shall seek to jointly agree upon an alternate rate of interest to the Eurodollar Rate that gives due consideration to the then prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time, and the Administrative Agent and the Borrower shall enter into an amendment to this Credit Agreement to reflect such alternate rate of interest and such other related changes to this Credit Agreement as may be applicable; provided that, notwithstanding anything to the contrary in Section 11.6, such amendment shall become effective without any further action or consent of any other party to this Credit Agreement so long as the Administrative Agent shall not have received, within five (5) Business Days of the date a copy of such amendment is provided to the Lenders, a written notice from the Required Lenders stating that such Required Lenders object to such amendment and (ii) until an alternate rate of interest shall be determined in accordance with this clause (b), (x) any request pursuant to Section 2.3 that requests the conversion of Base Rate Loans to Eurodollar Loans, or continuation of any Eurodollar Loans, shall be ineffective and any such Borrowing shall be continued as or converted to, as the case may be, a Base Rate Loan, and (y) if any request pursuant to Section 2.1 requests a Borrowing of Eurodollar Loans, such Borrowing shall be made as a Borrowing of Base Rate Loans; provided that, if such alternate rate of interest shall be less than zero, such rate shall be deemed to be zero for the purposes of this Credit Agreement.

(j)Section 4 of the Credit Agreement is hereby amended by adding the following as Section 4.1(m) thereto and re-numbering the current Section 4.1(m) to Section 4.1(n):

(m) Beneficial Ownership. At least five days prior to the First Amendment Effective Date, if the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation, the Borrower must deliver a Beneficial Ownership Certification in relation to the Borrower.

(k)Section 6 of the Credit Agreement is hereby amended by adding the following Section 6.22 thereto:

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6.22    Beneficial Ownership. As of the First Amendment Effective Date, the information included in any Beneficial Ownership Certification required to be delivered hereunder is true and correct in all respects.

(l)Section 7 of the Credit Agreement is hereby amended by adding the following as Section 7.1(h) thereto and re-numbering the current Section 7.1(h) to Section 7.1(i):

(h)    Beneficial Ownership Certification. Any change in the information provided in any Beneficial Ownership Certification required to be delivered hereunder that would result in a change to the list of beneficial owners identified in parts (c) or (d) of such certifications.

(m)Section 11.6 of the Credit Agreement is hereby amended to delete the first clause thereof in its entirety and to substitute the following clause therefor:

Except to the extent provided in Section 2.8 with respect to extensions of the Maturity Date and subject to Section 3.10(b), no amendment or waiver of any provision in this Credit Agreement or any other Credit Document, and no consent to any departure by the Borrower therefrom, shall be effective unless in writing signed by the Required Lenders and the Borrower and acknowledged by the Administrative Agent, and each such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no such amendment, waiver or consent shall:

2.    Effectiveness. This Amendment shall be effective on the date of receipt by the Administrative Agent of (i) copies of this Amendment duly executed by the Borrower, the Administrative Agent and the Lenders and (ii) the Administrative Agent’s and its affiliates’ fees and expenses (including fees and expenses of counsel for the Administrative Agent) in connection with this Amendment.

3.    Ratification of Credit Agreement. The term "Credit Agreement" as used in each of the Credit Documents shall hereafter mean the Credit Agreement as amended and modified by this Amendment and as amended and modified from time to time hereafter. Except as herein specifically agreed, the Credit Agreement, as amended by this Amendment, is hereby ratified and confirmed and shall remain in full force and effect according to its terms. Each party hereto acknowledges and consents to the modifications set forth herein and agrees that, other than as explicitly set forth in Section 1 above, this Amendment does not impair, reduce or limit any of its obligations under the Credit Documents (including, without limitation, the indemnity obligations set forth therein) and that, after the date hereof, this Amendment shall constitute a Credit Document.

4.    Authority/Enforceability. The Borrower represents and warrants as follows:

(a)    It has taken all necessary action to authorize the execution, delivery and performance of this Amendment.

(b)    This Amendment has been duly executed and delivered by the Borrower and constitutes the Borrower’s legal, valid and binding obligations, enforceable in accordance with its terms, except as such enforceability may be subject to (i) bankruptcy, insolvency, reorganization, fraudulent conveyance or transfer, moratorium or similar laws affecting creditors' rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).

(c)    No consent, approval, authorization or order of, or filing, registration or qualification with, any court or governmental authority or third party is required in connection with the execution, delivery or performance by the Borrower of this Amendment.

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5.    Representations and Warranties. The Borrower represents and warrants to the Lenders that (a) the representations and warranties of the Borrower set forth in Section 6 of the Credit Agreement are true and correct as of the date hereof, unless they specifically refer to an earlier date, except that all references in Section 6.7 of the Credit Agreement to December 31, 2016 shall be changed to December 31, 2018 for purposes hereof, (b) no event has occurred and is continuing which constitutes a Default or an Event of Default, and (c) it has no claims, counterclaims, offsets, credits or defenses to its obligations under the Credit Documents, or to the extent it has any, they are hereby released in consideration of the Lenders party hereto entering into this Amendment.

6.    No Conflicts. The Borrower represents and warrants that the execution and delivery of this Amendment, the consummation of the transactions contemplated herein and in the Credit Agreement (before and after giving effect to this Amendment), and the performance of and compliance with the terms and provisions hereof by the Borrower will not (a) violate, contravene or conflict with any provision of its articles or certificate of incorporation, bylaws or other organizational or governing document, (b) violate, contravene or conflict with any law, rule, regulation (including, without limitation, Regulation U and Regulation X), order, writ, judgment, injunction, decree or permit applicable to the Borrower, (c) violate, contravene or conflict with contractual provisions of, or cause an event of default under, any indenture, loan agreement, mortgage, deed of trust, contract or other agreement or instrument to which the Borrower is a party or by which it or its properties may be bound, the violation of which would have or would be reasonably expected to have a Material Adverse Effect or (d) result in or require the creation of any Lien upon or with respect to the Borrower's properties (except the Lien of the FMB Mortgage Documents in favor of the First Mortgage Bond Trustee).

7.    Counterparts/Telecopy. This Amendment may be executed in any number of counterparts, each of which when so executed and delivered shall be an original, but all of which shall constitute one and the same instrument. Delivery of executed counterparts by telecopy or by electronic format (pdf) shall be effective as an original.

8.    GOVERNING LAW. THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

[remainder of page intentionally left blank]

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Each of the parties hereto has caused a counterpart of this Amendment to be duly executed and delivered as of the date first above written.

BORROWER:

TEXAS-NEW MEXICO POWER COMPANY,

a Texas corporation

By:    /s/ Joseph D. Tarry

Name:    Joseph D. Tarry

Title:    Vice President, Controller and Treasurer

ADMINISTRATIVE AGENT:

KEYBANK, NATIONAL ASSOCIATION,

as Administrative Agent and as a Lender

By:    /s/ Keven D Smith

Name:    Keven D. Smith

Title:    Senior Vice President

LENDERS:                

JPMORGAN CHASE BANK, N.A.,

as a Lender

By:    /s/ Nancy R. Barwig

Name:    Nancy R. Barwig

Title:    Executive Director

MUFG UNION BANK, N.A.,

as a Lender

By:    /s/ Paul Farrell

Name:    Paul Farrell

Title:    Managing Director

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as a Lender

By:    /s/ Gregory R. Gredvig

Name:    Gregory R. Gredvig

Title:    Director

EX-10.7

FORM OF

FIRST AMENDMENT

TO THE

PNM RESOURCES, INC.

INDEMNITY AGREEMENT

This First Amendment to the PNM Resources, Inc. Indemnity Agreement (the “Agreement”) dated as of March __, 2019 is made and entered into by and between PNM Resources, Inc., a New Mexico corporation (the “Company”) and __________ (the “Indemnitee”).

WHEREAS, the Board of Directors of the Company (the “Board”) adopted the PNM Resources, Inc. Clawback Policy effective as of February 22, 2019 (the “Clawback Policy”);

WHEREAS, Section 8 of the Clawback Policy provides that the Company shall not indemnify any individual against the loss of incentive compensation recovered pursuant to the terms of the Clawback Policy;

WHEREAS, the Company and the Indemnitee previously entered into an Indemnity Agreement dated as of _____________ (the “Indemnity Agreement”);

WHEREAS, the Company and the Indemnitee wish to amend the Indemnity Agreement to reflect applicable restrictions under the Clawback Policy and related law.

NOW, THEREFORE, it is agreed that:

Section 2(f) of the Indemnity Agreement is hereby amended to add the following additional sentence to the end thereof:

In addition, notwithstanding any other provision of this Agreement, no indemnity will be provided to indemnify or reimburse the Indemnitee for the loss, repayment or recovery of any compensation pursuant to the application of the PNM Resources, Inc. Clawback Policy as adopted by the Board of Directors on February 22, 2019 and as it may be amended or replaced from time to time (the “Clawback Policy”), or the provisions of Section 304 of the Sarbanes-Oxley Act of 2002, Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, Section 10D of the 1934 Act, or any

regulations promulgated with respect to any of the foregoing, as any of the same are in effect from time to time.

IN WITNESS WHEREOF, the Company and the Indemnitee have executed this First Amendment as of the date set forth above.

PNM RESOURCES, INC.

By:

Name:

Title:

INDEMNITEE

By:

Name:

Title:

EX-31.1

PNM Resources

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.1

CERTIFICATION

I, Patricia K. Collawn, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 7, 2019	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chairman, President and Chief Executive Officer
			PNM Resources, Inc.

EX-31.2

PNM Resources

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.2

CERTIFICATION

I, Charles N. Eldred, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 7, 2019	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer
			PNM Resources, Inc.

EX-31.3

Public Service Company of New Mexico

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.3

CERTIFICATION

I, Patricia K. Collawn, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 7, 2019	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			Public Service Company of New Mexico

EX-31.4

Public Service Company of New Mexico

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.4

CERTIFICATION

I, Charles N. Eldred, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 7, 2019	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer
			Public Service Company of New Mexico

EX-31.5

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 31.5

CERTIFICATION

I, Patricia K. Collawn, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 7, 2019	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chief Executive Officer
			Texas-New Mexico Power Company

EX-31.6

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 31.6

CERTIFICATION

I, Charles N. Eldred, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 7, 2019	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer
			Texas-New Mexico Power Company

EX-32.1

PNM Resources

414 Silver Ave. SW

Albuquerque, NM 87102-3289

www.pnmresources.com

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended March 31, 2019, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on May 7, 2019 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 7, 2019	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chairman, President and Chief Executive Officer
			PNM Resources, Inc.
		By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer

EX-32.2

Public Service Company of New Mexico

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended March 31, 2019, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on May 7, 2019 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 7, 2019	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			Public Service Company of New Mexico
		By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer

EX-32.3

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 32.3

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended March 31, 2019, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on May 7, 2019 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 7, 2019	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chief Executive Officer
			Texas-New Mexico Power Company
		By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 03, 2019
Document Information [Line Items]
Entity Registrant Name	PNM RESOURCES INC
Entity Central Index Key	0001108426
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		79,653,624
PNM
Document Information [Line Items]
Entity Registrant Name	PUBLIC SERVICE CO OF NEW MEXICO
Entity Central Index Key	0000081023
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		39,117,799
Texas-New Mexico Power Company
Document Information [Line Items]
Entity Registrant Name	TEXAS NEW MEXICO POWER CO
Entity Central Index Key	0000022767
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		6,358

XML

Condensed Consolidated Statements of Earnings - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Electric Operating Revenues:
Contracts with customers	$ 315,698	$ 303,351
Revenues	349,645	317,878
Operating Expenses:
Administrative and general	52,336	48,283
Regulatory disallowances and restructuring costs	1,345	0
Depreciation and amortization	65,356	58,722
Transmission and distribution costs	16,678	16,955
Taxes other than income taxes	20,509	19,880
Total operating expenses	312,922	271,746
Operating income	36,723	46,132
Other Income and Deductions:
Interest income	3,619	4,124
Gains on investment securities	14,014	288
Other income	3,415	3,469
Other (deductions)	(3,252)	(1,376)
Net other income and deductions	17,796	6,505
Interest Charges	31,634	33,055
Earnings before Income Taxes	22,885	19,582
Income Taxes	1,223	783
Net Earnings	21,662	18,799
(Earnings) Attributable to Valencia Non-controlling Interest	(2,830)	(3,677)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)
Net Earnings Available for PNM Common Stock	$ 18,700	$ 14,990
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)	$ 0.23	$ 0.19
Diluted (dollars per share)	0.23	0.19
Dividends Declared per Common Share (dollars per share)	$ 0.29	$ 0.265
Alternative revenue programs
Electric Operating Revenues:
Revenues	$ 636	$ 924
Other electric operating revenue
Electric Operating Revenues:
Revenues	33,311	13,603
Electricity
Electric Operating Revenues:
Revenues	349,645	317,878
Operating Expenses:
Cost of energy and energy production costs	121,626	92,556
Electricity, Generation
Operating Expenses:
Cost of energy and energy production costs	35,072	35,350
PNM
Electric Operating Revenues:
Contracts with customers	235,941	222,564
Revenues	269,318	236,232
Operating Expenses:
Administrative and general	47,402	43,726
Regulatory disallowances and restructuring costs	1,345	0
Depreciation and amortization	39,224	36,627
Transmission and distribution costs	10,633	9,827
Taxes other than income taxes	12,010	11,608
Total operating expenses	245,025	207,940
Operating income	24,293	28,292
Other Income and Deductions:
Interest income	3,656	2,487
Gains on investment securities	14,014	288
Other income	2,632	2,391
Other (deductions)	(2,288)	(1,462)
Net other income and deductions	18,014	3,704
Interest Charges	18,360	20,830
Earnings before Income Taxes	23,947	11,166
Income Taxes	1,973	(348)
Net Earnings	21,974	11,514
(Earnings) Attributable to Valencia Non-controlling Interest	(2,830)	(3,677)
Net Earnings Attributable to PNMR	19,144	7,837
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)
Net Earnings Available for PNM Common Stock	19,012	7,705
PNM | Alternative revenue programs
Electric Operating Revenues:
Revenues	66	65
PNM | Other electric operating revenue
Electric Operating Revenues:
Revenues	33,311	13,603
PNM | Electricity
Operating Expenses:
Cost of energy and energy production costs	99,339	70,802
PNM | Electricity, Generation
Operating Expenses:
Cost of energy and energy production costs	35,072	35,350
Texas-New Mexico Power Company
Electric Operating Revenues:
Contracts with customers	79,757	80,787
Revenues	80,327	81,646
Operating Expenses:
Administrative and general	11,558	10,709
Depreciation and amortization	20,214	16,387
Transmission and distribution costs	6,045	7,128
Taxes other than income taxes	7,638	7,136
Total operating expenses	67,742	63,114
Operating income	12,585	18,532
Other Income and Deductions:
Interest income	31	0
Other income	717	754
Other (deductions)	(163)	331
Net other income and deductions	585	1,085
Interest Charges	8,800	7,729
Earnings before Income Taxes	4,370	11,888
Income Taxes	272	2,475
Net Earnings Attributable to PNMR	4,098	9,413
Texas-New Mexico Power Company | Alternative revenue programs
Electric Operating Revenues:
Revenues	570	859
Texas-New Mexico Power Company | Other electric operating revenue
Electric Operating Revenues:
Revenues	0	0
Texas-New Mexico Power Company | Electricity
Operating Expenses:
Cost of energy and energy production costs	$ 22,287	$ 21,754

XML

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Net Earnings	$ 21,662	$ 18,799
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	5,280	832
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(504)	(1,961)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit)	1,381	1,411
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $311 and $(472)	(914)
Change in fair market value, net of income tax (expense) benefit of $311 and $(472)		1,386
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(68) and $13	202
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(68) and $13		(40)
Total Other Comprehensive Income	5,445	1,628
Comprehensive Income	27,107	20,427
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(2,830)	(3,677)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)
Comprehensive Income Attributable to PNMR	24,145	16,618
PNM
Net Earnings	21,974	11,514
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	5,280	832
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(504)	(1,961)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit)	1,381	1,411
Fair Value Adjustment for Cash Flow Hedges:
Total Other Comprehensive Income	6,157	282
Comprehensive Income	28,131	11,796
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(2,830)	(3,677)
Comprehensive Income Attributable to PNMR	$ 25,301	$ 8,119

XML

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit	$ (1,798)	$ (283)
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit)	172	668
Pension liability adjustment, income tax expense (benefit)	(470)	(480)
Change in fair market value, net of income tax (expense) benefit of $311 and $(472)	311
Change in fair market value, income tax (expense) benefit		(472)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(68) and $13	(68)
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)		13
PNM
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit	(1,798)	(283)
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit)	172	668
Pension liability adjustment, income tax expense (benefit)	$ (470)	$ (480)

XML

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash Flows From Operating Activities:
Net Earnings	$ 21,662	$ 18,799
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	73,946	67,748
Deferred income tax expense	1,122	767
(Gains) on investment securities	(14,014)	(288)
Stock based compensation expense	3,257	2,894
Regulatory disallowances and restructuring costs	1,345	0
Allowance for equity funds used during construction	(2,049)	(2,487)
Other, net	444	729
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	15,842	18,215
Materials and supplies	3,826	(2,976)
Other current assets	(1,778)	2,345
Other assets	13,463	(443)
Accounts payable	(7,642)	(26,953)
Accrued interest and taxes	6,443	13,370
Other current liabilities	2,060	(9,397)
Other liabilities	(13,243)	(3,397)
Net cash flows from operating activities	104,684	78,926
Cash Flows From Investing Activities:
Additions to utility plant	(141,986)	(117,691)
Proceeds from sales of investment securities	74,460	626,729
Purchases of investment securities	(77,363)	(628,999)
Principal repayments on Westmoreland Loan	0	5,649
Investments in NMRD	(7,000)	(5,000)
Other, net	(13)	128
Net cash flows from investing activities	(151,902)	(119,184)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	(12,100)	(66,700)
Long-term borrowings	475,000	299,652
Repayment of long-term debt	(200,000)	(155,026)
Proceeds from stock option exercise	930	802
Awards of common stock	(8,936)	(10,845)
Dividends paid	(23,232)	(21,240)
Valencia’s transactions with its owner	(4,263)	(4,472)
Debt issuance costs and other, net	(2,215)	(2,104)
Net cash flows from financing activities	225,184	40,067
Change in Cash, Restricted Cash, and Equivalents	177,966	(191)
Cash, Restricted Cash, and Equivalents at End of Period	180,088	3,783
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	20,518	15,305
Income taxes paid (refunded), net	(235)	(8)
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	26,636	16,003
PNM
Cash Flows From Operating Activities:
Net Earnings	21,974	11,514
Net earnings	19,144	7,837
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	47,218	45,165
Deferred income tax expense	2,063	(253)
(Gains) on investment securities	(14,014)	(288)
Regulatory disallowances and restructuring costs	1,345	0
Allowance for equity funds used during construction	(1,807)	(2,031)
Other, net	432	729
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	15,212	15,100
Materials and supplies	3,671	(2,247)
Other current assets	(4,098)	(248)
Other assets	10,399	3,999
Accounts payable	(8,257)	(18,014)
Accrued interest and taxes	14,764	17,984
Other current liabilities	32,683	(13,868)
Other liabilities	(13,524)	(4,381)
Net cash flows from operating activities	108,061	53,161
Cash Flows From Investing Activities:
Additions to utility plant	(75,876)	(61,720)
Proceeds from sales of investment securities	74,460	626,729
Purchases of investment securities	(77,363)	(628,999)
Other, net	(48)	128
Net cash flows from investing activities	(78,827)	(63,862)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	(42,400)	(39,800)
Short-term borrowings (repayments) – affiliate, net	(19,800)	54,600
Long-term borrowings	250,000	0
Repayment of long-term debt	(200,000)	0
Dividends paid	(132)	(132)
Valencia’s transactions with its owner	(4,263)	(4,472)
Debt issuance costs and other, net	(635)	(584)
Net cash flows from financing activities	(17,230)	9,612
Change in Cash, Restricted Cash, and Equivalents	12,004	(1,089)
Cash, Restricted Cash, and Equivalents at End of Period	12,089	19
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	9,070	9,560
Income taxes paid (refunded), net	0	0
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	11,407	2,682
Texas-New Mexico Power Company
Cash Flows From Operating Activities:
Net earnings	4,098	9,413
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	20,514	16,836
Deferred income tax expense	(4,343)	(953)
Allowance for equity funds used during construction	(231)	(456)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	630	3,115
Materials and supplies	155	(729)
Other current assets	581	331
Other assets	2,712	(3,055)
Accounts payable	1,075	(4,400)
Accrued interest and taxes	(990)	(1,952)
Other current liabilities	3,190	5,874
Other liabilities	(1,536)	1,456
Net cash flows from operating activities	25,855	25,480
Cash Flows From Investing Activities:
Additions to utility plant	(58,624)	(49,956)
Net cash flows from investing activities	(58,624)	(49,956)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	(17,500)	21,200
Short-term borrowings (repayments) – affiliate, net	(100)	2,600
Long-term borrowings	225,000	0
Dividends paid	(10,713)	(1,024)
Debt issuance costs and other, net	(1,561)	0
Net cash flows from financing activities	195,126	22,776
Cash, Restricted Cash, and Equivalents at End of Period	162,357
Change in Cash and Cash Equivalents	162,357	(1,700)
Cash and Cash Equivalents at Beginning of Period	0	1,700
Cash and Cash Equivalents at End of Period	162,357	0
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	3,829	1,830
Income taxes paid (refunded), net	(235)	(8)
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$ 10,646	$ 9,868

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Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current Assets:
Cash and cash equivalents	$ 180,088	$ 2,122
Accounts receivable, net of allowance for uncollectible accounts	94,624	92,800
Unbilled revenues	39,011	57,092
Other receivables	13,849	11,369
Materials, supplies, and fuel stock	68,008	71,834
Regulatory assets	0	4,534
Income taxes receivable	7,630	7,965
Other current assets	53,863	54,808
Total current assets	457,073	302,524
Other Property and Investments:
Investment securities	351,563	328,242
Equity investment in NMRD	33,528	26,564
Other investments	299	297
Non-utility property, net	6,229	3,404
Total other property and investments	391,619	358,507
Utility Plant:
Plant in service and held for future use	7,610,093	7,548,581
Less accumulated depreciation and amortization	2,641,320	2,604,177
Net plant in service and plant held for future use	4,968,773	4,944,404
Construction work in progress	225,485	194,427
Nuclear fuel, net of accumulated amortization	95,713	95,798
Net utility plant	5,289,971	5,234,629
Deferred Charges and Other Assets:
Regulatory assets	588,266	598,930
Goodwill	278,297	278,297
Operating lease right-of-use assets, net of accumulated amortization	150,426
Other deferred charges	95,106	92,664
Total deferred charges and other assets	1,112,095	969,891
Total assets	7,250,758	6,865,551
Current Liabilities:
Short-term debt	223,800	235,900
Current installments of long-term debt	172,302	0
Accounts payable	77,893	112,170
Customer deposits	10,749	10,695
Accrued interest and taxes	71,264	65,156
Regulatory liabilities	19,245	9,446
Operating lease liabilities	26,197
Dividends declared	23,231	23,231
Other current liabilities	39,452	55,855
Total current liabilities	664,133	512,453
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	2,771,939	2,670,111
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	613,989	600,719
Regulatory liabilities	889,342	891,428
Asset retirement obligations	161,685	158,674
Accrued pension liability and postretirement benefit cost	96,374	100,375
Operating lease liabilities	124,937
Other deferred credits	169,372	167,668
Total deferred credits and other liabilities	2,055,699	1,918,864
Total liabilities	5,491,771	5,101,428
Commitments and Contingencies (Note 11)
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
Company common stockholders’ equity:
Common stock	1,148,364	1,153,113
Accumulated other comprehensive income (loss), net of income taxes	(103,239)	(108,684)
Retained earnings	639,554	643,953
Total stockholders' equity	1,684,679	1,688,382
Non-controlling interest in Valencia	62,779	64,212
Total equity	1,747,458	1,752,594
Total liabilities and stockholders' equity	7,250,758	6,865,551
PNM
Current Assets:
Cash and cash equivalents	12,089	85
Accounts receivable, net of allowance for uncollectible accounts	68,724	68,603
Unbilled revenues	31,366	47,113
Other receivables	14,370	10,650
Affiliate receivables	8,854	15,871
Materials, supplies, and fuel stock	63,426	67,097
Regulatory assets	0	4,534
Income taxes receivable	12,940	12,850
Other current assets	43,650	43,516
Total current assets	255,419	270,319
Other Property and Investments:
Investment securities	351,563	328,242
Other investments	93	91
Non-utility property, net	1,693	96
Total other property and investments	353,349	328,429
Utility Plant:
Plant in service and held for future use	5,664,174	5,623,520
Less accumulated depreciation and amortization	2,033,511	2,006,266
Net plant in service and plant held for future use	3,630,663	3,617,254
Construction work in progress	143,673	134,221
Nuclear fuel, net of accumulated amortization	95,713	95,798
Net utility plant	3,870,049	3,847,273
Deferred Charges and Other Assets:
Regulatory assets	454,987	460,903
Goodwill	51,632	51,632
Operating lease right-of-use assets, net of accumulated amortization	137,756
Other deferred charges	78,847	77,327
Total deferred charges and other assets	723,222	589,862
Total assets	5,202,039	5,035,883
Current Liabilities:
Short-term debt	0	42,400
Short-term debt - affiliate	0	19,800
Accounts payable	55,449	75,114
Affiliate payables	12,627	164
Customer deposits	10,749	10,695
Accrued interest and taxes	50,621	35,767
Regulatory liabilities	16,895	5,975
Operating lease liabilities	22,762
Dividends declared	132	132
Other current liabilities	26,432	32,976
Total current liabilities	195,667	223,023
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,706,873	1,656,490
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	513,783	502,767
Regulatory liabilities	708,295	713,971
Asset retirement obligations	160,807	157,814
Accrued pension liability and postretirement benefit cost	89,338	92,981
Operating lease liabilities	115,436
Other deferred credits	215,004	215,737
Total deferred credits and other liabilities	1,802,663	1,683,270
Total liabilities	3,705,203	3,562,783
Commitments and Contingencies (Note 11)
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
Company common stockholders’ equity:
Common stock	1,264,918	1,264,918
Accumulated other comprehensive income (loss), net of income taxes	(104,265)	(110,422)
Retained earnings	261,875	242,863
Total stockholders' equity	1,422,528	1,397,359
Non-controlling interest in Valencia	62,779	64,212
Total equity	1,485,307	1,461,571
Total liabilities and stockholders' equity	5,202,039	5,035,883
Texas-New Mexico Power Company
Current Assets:
Cash and cash equivalents	162,357	0
Accounts receivable, net of allowance for uncollectible accounts	25,900	24,196
Unbilled revenues	7,645	9,979
Other receivables	881	1,721
Affiliate receivables	0	164
Materials, supplies, and fuel stock	4,582	4,737
Other current assets	1,373	1,114
Total current assets	202,738	41,911
Other Property and Investments:
Other investments	206	206
Non-utility property, net	3,468	2,240
Total other property and investments	3,674	2,446
Utility Plant:
Plant in service and held for future use	1,702,427	1,686,119
Less accumulated depreciation and amortization	491,776	487,734
Net plant in service and plant held for future use	1,210,651	1,198,385
Construction work in progress	75,332	51,459
Net utility plant	1,285,983	1,249,844
Deferred Charges and Other Assets:
Regulatory assets	133,279	138,027
Goodwill	226,665	226,665
Operating lease right-of-use assets, net of accumulated amortization	12,160
Other deferred charges	7,281	6,284
Total deferred charges and other assets	379,385	370,976
Total assets	1,871,780	1,665,177
Current Liabilities:
Short-term debt	0	17,500
Current installments of long-term debt	172,302	0
Short-term debt - affiliate	0	100
Accounts payable	14,234	23,804
Affiliate payables	4,771	1,210
Accrued interest and taxes	40,892	41,882
Regulatory liabilities	2,350	3,471
Operating lease liabilities	3,023
Other current liabilities	3,556	2,861
Total current liabilities	241,128	90,828
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	626,639	575,398
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	134,757	136,238
Regulatory liabilities	181,047	177,458
Asset retirement obligations	878	860
Accrued pension liability and postretirement benefit cost	7,036	7,394
Operating lease liabilities	9,088
Other deferred credits	3,729	2,908
Total deferred credits and other liabilities	336,535	324,858
Total liabilities	1,204,302	991,084
Commitments and Contingencies (Note 11)
Company common stockholders’ equity:
Common stock	64	64
Paid-in-capital	534,166	534,166
Retained earnings	133,248	139,863
Total stockholders' equity	667,478	674,093
Total liabilities and stockholders' equity	$ 1,871,780	$ 1,665,177

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Allowance for uncollectible accounts	$ 1,151	$ 1,406
Accumulated depreciation, nuclear fuel	$ 48,675	$ 42,511
Cumulative preferred stock of subsidiary, stated value (in dollars per share)	$ 100	$ 100
Cumulative preferred stock of subsidiary, shares authorized (in shares)	10,000,000	10,000,000
Cumulative preferred stock of subsidiary, shares issued (in shares)	115,293	115,293
Cumulative preferred stock of subsidiary, shares outstanding (in shares)	115,293	115,293
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	120,000,000	120,000,000
Common stock, shares issued (in shares)	79,653,624	79,653,624
Common stock, shares outstanding (in shares)	79,653,624	79,653,624
PNM
Allowance for uncollectible accounts	$ 1,151	$ 1,406
Accumulated depreciation, nuclear fuel	$ 48,675	$ 42,511
Cumulative preferred stock, stated value (in dollars per share)	$ 100	$ 100
Cumulative preferred stock, shares authorized (in shares)	10,000,000	10,000,000
Cumulative preferred stock, shares issued (in shares)	115,293	115,293
Cumulative preferred stock, shares outstanding (in shares)	115,293	115,293
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	40,000,000	40,000,000
Common stock, shares issued (in shares)	39,117,799	39,117,799
Common stock, shares outstanding (in shares)	39,117,799	39,117,799
Texas-New Mexico Power Company
Common stock, par value (in dollars per share)	$ 10	$ 10
Common stock, shares authorized (in shares)	12,000,000	12,000,000
Common stock, shares issued (in shares)	6,358	6,358
Common stock, shares outstanding (in shares)	6,358	6,358

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Condensed Consolidated Statement of Changes in Equity - USD ($) $ in Thousands	Total	Total PNMR Common Stockholders’ Equity	Common Stock	AOCI	Retained Earnings	Non- controlling Interest in Valencia	PNM	PNM Total PNMR Common Stockholders’ Equity	PNM Common Stock	PNM AOCI	PNM Retained Earnings	PNM Non- controlling Interest in Valencia	Texas-New Mexico Power Company	Texas-New Mexico Power Company Common Stock	Texas-New Mexico Power Company Paid-in Capital	Texas-New Mexico Power Company Retained Earnings
Beginning balance at Dec. 31, 2017	$ 1,761,448	$ 1,695,253	$ 1,157,665	$ (95,940)	$ 633,528	$ 66,195	$ 1,488,369	$ 1,422,174	$ 1,264,918	$ (97,093)	$ 254,349	$ 66,195
Beginning balance TNMP at Dec. 31, 2017													$ 634,405	$ 64	$ 504,166	$ 130,175
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings before subsidiary preferred stock dividends	18,799	15,122			15,122	3,677	11,514	7,837			7,837	3,677
Net earnings							7,837						9,413			9,413
Total other comprehensive income	1,628	1,628		1,628			282	282		282
Subsidiary preferred stock dividends	(132)	(132)			(132)
Dividends declared on preferred stock							(132)	(132)			(132)
Dividends declared on common stock	(21,108)	(21,108)			(21,108)								(1,024)			(1,024)
Proceeds from stock option exercise	802	802	802
Awards of common stock	(10,845)	(10,845)	(10,845)
Stock based compensation expense	2,894	2,894	2,894
Valencia’s transactions with its owner	(4,472)					(4,472)	(4,472)					(4,472)
Ending balance at Mar. 31, 2018	1,749,014	1,683,614	1,150,516	(105,520)	638,618	65,400	1,495,561	1,430,161	1,264,918	(108,019)	273,262	65,400
Ending balance TNMP at Mar. 31, 2018													642,794	64	504,166	138,564
Beginning balance at Dec. 31, 2018	1,752,594	1,688,382	1,153,113	(108,684)	643,953	64,212	1,461,571	1,397,359	1,264,918	(110,422)	242,863	64,212
Beginning balance TNMP at Dec. 31, 2018	1,688,382						1,397,359						674,093	64	534,166	139,863
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings before subsidiary preferred stock dividends	21,662	18,832			18,832	2,830	21,974	19,144			19,144	2,830
Net earnings							19,144						4,098			4,098
Total other comprehensive income	5,445	5,445		5,445			6,157	6,157		6,157
Subsidiary preferred stock dividends	(132)	(132)			(132)
Dividends declared on preferred stock							(132)	(132)			(132)
Dividends declared on common stock	(23,099)	(23,099)			(23,099)								(10,713)			(10,713)
Proceeds from stock option exercise	930	930	930
Awards of common stock	(8,936)	(8,936)	(8,936)
Stock based compensation expense	3,257	3,257	3,257
Valencia’s transactions with its owner	(4,263)					(4,263)	(4,263)					(4,263)
Ending balance at Mar. 31, 2019	1,747,458	$ 1,684,679	$ 1,148,364	$ (103,239)	$ 639,554	$ 62,779	1,485,307	$ 1,422,528	$ 1,264,918	$ (104,265)	$ 261,875	$ 62,779
Ending balance TNMP at Mar. 31, 2019	$ 1,684,679						$ 1,422,528						$ 667,478	$ 64	$ 534,166	$ 133,248

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Significant Accounting Policies and Responsibility for Financial Statements

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Significant Accounting Policies and Responsibility for Financial Statements

Significant Accounting Policies and Responsibility for Financial Statements

Financial Statement Preparation

In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at March 31, 2019 and December 31, 2018, and the consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2019 and 2018. 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. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.

The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. 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 2018 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2019 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual audited Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s, and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2018 Annual Reports on Form 10-K.

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 Condensed 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 6). 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’ expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, equity transactions, and interconnection billings (Note 15). All intercompany transactions and balances have been eliminated.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by the Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board.

TNMP declared and paid cash dividends on common stock to PNMR of $10.7 million and $1.0 million in the three months ended March 31, 2019 and 2018.

Investment in NM Renewable Development, LLC

As discussed in Note 1 of the 2018 Annual Reports on Form 10-K, PNMR Development and AEP OnSite Partners created NMRD in September 2017 to pursue the acquisition, development, and ownership of renewable energy generation projects, primarily in the state of New Mexico. NMRD’s current renewable energy capacity in operation is 33.9 MW. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. The investment in NMRD is accounted for using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over NMRD and its operations.

In the three months ended March 31, 2019 and 2018, PNMR Development made cash contributions of $7.0 million and $5.0 million to NMRD to be used primarily for its construction activities. For the three months ended March 31, 2019 and 2018, NMRD had revenues of $0.7 million and $0.4 million and net earnings (losses) of $(0.1) million and $0.1 million. At March 31, 2019 and December 31, 2018, NMRD had $8.0 million and $2.6 million of current assets, $65.2 million and $50.8 million of property, plant, and equipment and other assets, $6.1 million and $0.2 million of current liabilities, and $67.1 million and $53.2 million of owners’ equity.

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.

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 certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. In November 2018, the FASB clarified that receivables arising from operating leases are not within the scope of Topic 326 for assets measured at amortized costs. Instead, impairments of receivables arising from operating leases should be accounted for in accordance with Topic 842. The Company anticipates adopting ASU 2016-13 as of January 1, 2020, its required effective date. The Company is in the process of analyzing the impacts of this new standard, but does not anticipate it will have a significant impact on its financial statements.

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, 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 2018-13 – Fair Value Measurements (Topic 820) Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurements

In August 2018, the FASB issued ASU 2018-13 to improve fair value disclosures. ASU 2018-13 eliminates certain disclosure requirements related to transfers between Levels 1 and 2 of the fair value hierarchy and the requirement to disclose the valuation process for Level 3 fair value measurements. ASU 2018-13 also amends certain disclosure requirements for investments measured at net asset value and requires new disclosures for Level 3 investments, including a new requirement to disclose changes in unrealized gains or losses recorded in OCI related to Level 3 fair value measurements. ASU 2018-13 is effective for the Company beginning on January 1, 2020, and permits entities to adopt all or certain elements of the new guidance prior to its effective date. ASU 2018-13 requires retrospective application, except for the new disclosures related to Level 3 investments which are to be applied prospectively. As discussed in Note 9 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 7, PNM and TNMP have investment securities in trusts for decommissioning, reclamation, pension benefits, and other postretirement benefits, which are measured at fair value. Certain investments in these trusts are measured at net asset value per share. These trusts also hold Level 3 investments. The Company is evaluating the requirements of ASU 2018-13, but does not anticipate it will have a significant impact on the Company’s fair value disclosures.

Accounting Standards Update 2018-14 – Compensation - Retirement Benefits - Defined Benefit Plans (Topic 715) Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans

In August 2018, the FASB issued ASU 2018-14 to improve benefit plan sponsors’ disclosures for defined benefit pension and other post-employment benefit plans. ASU 2018-14 removes the requirement to disclose the amounts in other comprehensive income expected to be recognized as benefit cost over the next fiscal year and the requirement to disclose the impact of a one-percentage-point change in the assumed health care cost trend rate; clarifies the disclosure requirements for plans with assets that are less than their projected benefit, or accumulated benefit obligation; and requires significant gains and losses affecting benefit obligations during the period be disclosed. ASU 2018-14 is effective for the Company on December 31, 2020, although early adoption is permitted, and requires retrospective application. As discussed in Note 11 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 10, PNM and TNMP maintain qualified defined benefit, other postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The Company is evaluating the requirements of ASU 2018-14 but does not anticipate these changes will have a significant impact on the Company’s defined benefit and other postretirement benefit plan disclosures.

Accounting Standards Update 2018-15 – Intangibles - Goodwill and Other - Internal Use Software (Topic 350): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract

In August 2018, the FASB issued ASU 2018-15 to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for implementation costs incurred to develop or obtain internal-use software. Under ASU 2018-15, entities are required to capitalize implementation costs for hosting arrangements if those costs meet the capitalization requirements for internal-use software arrangements. ASU 2018-15 requires entities to present cash flows, capitalized costs, and amortization expense in the same financial statement line items as other costs incurred for such hosting arrangements. ASU 2018-15 is effective for the Company on January 1, 2020, although early adoption is permitted, and allows entities to apply the new requirements retrospectively or prospectively. The Company is in the process of analyzing the impacts of this new standard.

Accounting Standards Update 2018-18 - Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606

In November 2018, the FASB issued ASU 2018-18 to clarify transactions between collaborative arrangement participants that should be recognized as revenue under Topic 606. ASU 2018-18 is effective for the Company on January 1, 2020, although early adoption is permitted, and requires retrospective application. The Company has collaborative arrangements related to its interests in SJGS, Four Corners, PVNGS, and Luna. The Company believes its current accounting practices comply with the requirements of ASU 2018-18 but is in the process of analyzing the impacts of the new standard.

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Segment Information

3 Months Ended

Mar. 31, 2019

Segment Reporting [Abstract]

Segment Information

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 capacity, as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale power and transmission rates.

TNMP

TNMP is an electric utility providing services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. TNMP also provides transmission services at regulated rates to other utilities that interconnect with TNMP’s facilities.

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, NM Capital, and the equity method investment in NMRD are also included in Corporate and Other. Eliminations of intercompany income and expense transactions are reflected in the Corporate and Other segment.

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

PNMR SEGMENT INFORMATION

	PNM			TNMP			Corporate and Other			PNMR Consolidated
	(In thousands)
Three Months Ended March 31, 2019
Electric operating revenues	$	269,318		$	80,327		$	—		$	349,645
Cost of energy	99,339			22,287			—			121,626
Utility margin	169,979			58,040			—			228,019
Other operating expenses	106,462			25,241			(5,763		)	125,940
Depreciation and amortization	39,224			20,214			5,918			65,356
Operating income (loss)	24,293			12,585			(155		)	36,723
Interest income	3,656			31			(68		)	3,619
Other income (deductions)	14,358			554			(735		)	14,177
Interest charges	(18,360		)	(8,800		)	(4,474		)	(31,634		)
Segment earnings (loss) before income taxes	23,947			4,370			(5,432		)	22,885
Income taxes (benefit)	1,973			272			(1,022		)	1,223
Segment earnings (loss)	21,974			4,098			(4,410		)	21,662
Valencia non-controlling interest	(2,830		)	—			—			(2,830		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	19,012		$	4,098		$	(4,410	)	$	18,700
At March 31, 2019:
Total Assets	$	5,202,039		$	1,871,780		$	176,939		$	7,250,758
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	PNM			TNMP			Corporate and Other			PNMR Consolidated
	(In thousands)
Three Months Ended March 31, 2018
Electric operating revenues	$	236,232		$	81,646		$	—		$	317,878
Cost of energy	70,802			21,754			—			92,556
Utility margin	165,430			59,892			—			225,322
Other operating expenses	100,511			24,973			(5,016		)	120,468
Depreciation and amortization	36,627			16,387			5,708			58,722
Operating income (loss)	28,292			18,532			(692		)	46,132
Interest income	2,487			—			1,637			4,124
Other income (deductions)	1,217			1,085			79			2,381
Interest charges	(20,830		)	(7,729		)	(4,496		)	(33,055		)
Segment earnings (loss) before income taxes	11,166			11,888			(3,472		)	19,582
Income taxes (benefit)	(348		)	2,475			(1,344		)	783
Segment earnings (loss)	11,514			9,413			(2,128		)	18,799
Valencia non-controlling interest	(3,677		)	—			—			(3,677		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	7,705		$	9,413		$	(2,128	)	$	14,990
At March 31, 2018:
Total Assets	$	4,925,741		$	1,526,434		$	224,218		$	6,676,393
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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Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2019

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2019 and 2018 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	PNM									PNMR
	Unrealized									Fair Value
	Gains on									Adjustment
	Available-for-			Pension						for Cash
	Sale			Liability						Flow
	Securities			Adjustment			Total			Hedges			Total
	(In thousands)
Balance at December 31, 2018	$	1,939		$	(112,361	)	$	(110,422	)	$	1,738		$	(108,684	)
Amounts reclassified from AOCI (pre-tax)	(676		)	1,851			1,175			270			1,445
Income tax impact of amounts reclassified	172			(470		)	(298		)	(68		)	(366		)
Other OCI changes (pre-tax)	7,078			—			7,078			(1,225		)	5,853
Income tax impact of other OCI changes	(1,798		)	—			(1,798		)	311			(1,487		)
Net after-tax change	4,776			1,381			6,157			(712		)	5,445
Balance at March 31, 2019	$	6,715		$	(110,980	)	$	(104,265	)	$	1,026		$	(103,239	)

Balance at December 31, 2017, as originally reported	$	13,169		$	(110,262	)	$	(97,093	)	$	1,153		$	(95,940	)
Cumulative effect adjustment (Note 7)	(11,208		)	—			(11,208		)	—			(11,208		)
Balance at January 1, 2018, as adjusted	1,961			(110,262		)	(108,301		)	1,153			(107,148		)
Amounts reclassified from AOCI (pre-tax)	(2,629		)	1,891			(738		)	(53		)	(791		)
Income tax impact of amounts reclassified	668			(480		)	188			13			201
Other OCI changes (pre-tax)	1,115			—			1,115			1,858			2,973
Income tax impact of other OCI changes	(283		)	—			(283		)	(472		)	(755		)
Net after-tax change	(1,129		)	1,411			282			1,346			1,628
Balance at March 31, 2018	$	832		$	(108,851	)	$	(108,019	)	$	2,499		$	(105,520	)

The Condensed Consolidated Statements of Earnings include pre-tax amounts reclassified from AOCI related to Unrealized Gains on Available-for-Sale Securities in gains on investment securities, related to Pension Liability Adjustment in other (deductions), and related to Fair Value Adjustment for Cash Flow Hedges in interest charges. The income tax impacts of all amounts reclassified from AOCI are included in income taxes in the Condensed Consolidated Statements of Earnings.

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Earnings Per Share

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

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

	Three Months Ended
	March 31,
	2019		2018
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	18,700	$	14,990
Average Number of Common Shares:
Outstanding during period	79,654		79,654
Vested awards of restricted stock	239		205
Average Shares – Basic	79,893		79,859
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	78		154
Average Shares – Diluted	79,971		80,013
Net Earnings Per Share of Common Stock:
Basic	$	0.23	$	0.19
Diluted	$	0.23	$	0.19

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Electric Operating Revenues

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Electric Operating Revenues

Electric Operating Revenues

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.

Additional information concerning electric operating revenue is contained in Note 4 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Disaggregation of Revenues

A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects alternative revenue program revenues (“ARP”) and other revenues.

	PNM		TNMP		PNMR Consolidated
Three Months Ended March 31, 2019	(In thousands)
Electric Operating Revenues:
Contracts with customers:
Retail electric revenue
Residential	$	107,302	$	30,432	$	137,734
Commercial	85,233		27,429		112,662
Industrial	14,747		5,616		20,363
Public authority	4,711		1,374		6,085
Economy energy service	6,922		—		6,922
Transmission	13,385		14,003		27,388
Miscellaneous	3,641		903		4,544
Total revenues from contracts with customers	235,941		79,757		315,698
Alternative revenue programs	66		570		636
Other electric operating revenues	33,311		—		33,311
Total Electric Operating Revenues	$	269,318	$	80,327	$	349,645

	PNM		TNMP		PNMR Consolidated
Three Months Ended March 31, 2018	(In thousands)
Electric Operating Revenues:
Contracts with customers:
Retail electric revenue
Residential	$	97,169	$	29,266	$	126,435
Commercial	82,849		27,152		110,001
Industrial	13,459		4,305		17,764
Public authority	4,635		1,416		6,051
Economy energy service	7,288		—		7,288
Transmission	12,482		16,508		28,990
Miscellaneous	4,682		2,140		6,822
Total revenues from contracts with customers	222,564		80,787		303,351
Alternative revenue programs	65		859		924
Other electric operating revenues	13,603		—		13,603
Total Electric Operating Revenues	$	236,232	$	81,646	$	317,878

Contract balances

Performance obligations related to contracts with customers are typically satisfied when the energy is delivered and the customer or end-user utilizes the energy. Accounts receivable from customers represent amounts billed to the customer or end-user, including amounts under ARP programs. For PNM, accounts receivable reflected on the Condensed Consolidated Balance Sheets, net of allowance for uncollectible accounts, includes $65.2 million at March 31, 2019 and $61.7 million at December 31, 2018 resulting from contracts with customers. All of TNMP’s accounts receivable results from contracts with customers.

Contract assets are an entity’s right to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditioned on something other than the passage of time (for example, the entity’s future performance). The Company has no contract assets as of March 31, 2019 or December 31, 2018. Contract liabilities arise when consideration is received in advance from a customer before satisfying the performance obligations. Therefore, revenue is deferred and not recognized until the obligation is satisfied. Under its Open Access Transmission Tariff, PNM accepts upfront consideration for capacity reservations requested by transmission customers, which requires PNM to defer the customer’s transmission capacity rights for a specific period of time. PNM recognizes the revenue of these capacity reservations over the period the capacity rights have been reserved, which is generally over one year. Other utilities pay PNM and TNMP in advance for the joint-use of their utility poles. These revenues are recognized over the period of time specified in the joint-use contract, typically for one calendar year. Deferred revenues on these arrangements are recorded as contract liabilities. The Company has no other arrangements with remaining performance obligations to which a portion of the transaction price would be required to be allocated.

Changes during the period in the balances of contract liabilities, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, are as follows:

	PNM			TNMP			PNMR Consolidated
	(In thousands)
Balance at December 31, 2018	$	349		$	—		$	349
Consideration received in advance of service to be provided	3,981			1,389			5,370
Deferred revenue earned	(1,349		)	(371		)	(1,720		)
Balance at March 31, 2019	$	2,981		$	1,018		$	3,999

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Variable Interest Entities

3 Months Ended

Mar. 31, 2019

Variable Interest Entities [Abstract]

Variable Interest Entities

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. Additional information concerning PNM’s VIEs is contained in Note 10 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

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 three months ended March 31, 2019 and 2018, PNM paid $4.9 million and $4.9 million for fixed charges and less than $0.1 million and $0.3 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 Condensed 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 Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

	Results of Operations
	Three Months Ended March 31,
	2019			2018
	(In thousands)
Operating revenues	$	4,952		$	4,768
Operating expenses	(2,122		)	(1,091		)
Earnings attributable to non-controlling interest	$	2,830		$	3,677

	Financial Position
	March 31,		December 31,
	2019		2018
	(In thousands)
Current assets	$	2,918	$	2,684
Net property, plant, and equipment	60,712		62,066
Total assets	63,630		64,750
Current liabilities	851		538
Owners’ equity – non-controlling interest	$	62,779	$	64,212

Westmoreland San Juan Mining, LLC

As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS under a coal supply agreement (“SJGS CSA”). That section includes information on the acquisition of SJCC by WSJ, a subsidiary of Westmoreland Coal Company (“Westmoreland”), on January 31, 2016, as well as the $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 purchase of SJCC. On May 22, 2018, the full principal outstanding under the Westmoreland Loan of $50.1 million was repaid. NM Capital used a portion of the proceeds to repay all remaining amounts owed under the BTMU Term Loan. These payments effectively terminated the loan agreements and PNMR’s guarantee of NM Capital’s obligations under the BTMU Term Loan. Prior to its repayment, the Westmoreland Loan resulted in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital were subject to possible loss in the event of default of WSJ.

On October 9, 2018, Westmoreland filed a Current Report on Form 8-K with the SEC announcing it had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. On March 15, 2019, Westmoreland emerged from Chapter 11 bankruptcy as a privately held company owned and operated by a group of its former creditors. Under the reorganization, the assets of SJCC were sold to Westmoreland San Juan Mining, LLC (“WSJ LLC”), a subsidiary of Westmoreland Mining Holdings, LLC. The March 15, 2019 announcement indicated that mining operations will continue in the normal course of business. As successor entity to SJCC, WSJ LLC assumed all rights and obligations of WSJ including obligations to PNM under the SJGS CSA and to PNMR for the letters of credit support agreement. See (Note 11).

PNMR issued $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. As discussed above, WSJ LLC assumed the rights and obligations of SJCC, including obligations to PNMR for the letters of credit. The letters of credit support results in PNMR being considered to have a variable interest in WSJ LLC since PNMR is subject to possible loss in the event performance by PNMR is required under the letters of credit support. 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 WSJ LLC 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. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations.

WSJ LLC is considered to be a VIE.  PNMR’s analysis of its arrangements with WSJ LLC concluded that WSJ LLC has the ability to direct its mining operations, which is the factor that most significantly impacts the economic performance of WSJ LLC.  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 WSJ LLC, 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.  PNM’s involvement through the SJGS CSA, which was assumed by WSJ LLC pursuant to the March 15, 2019 purchase of the assets owned by SJCC by WSJ LLC, is a protective right rather than a participating right and WSJ LLC has the power to direct the activities that most significantly impact the economic performance of WSJ LLC.  The SJGS CSA requires WSJ LLC 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 WSJ LLC is able to mine more efficiently than anticipated, its economic performance will be improved.  Conversely, if WSJ LLC cannot mine as efficiently as anticipated, its economic performance will be negatively impacted.  Accordingly, PNMR believes WSJ LLC is the primary beneficiary and, therefore, WSJ LLC is not consolidated by either PNMR or PNM. The amounts outstanding under the letter of credit support constitute PNMR’s maximum exposure to loss from the VIE at March 31, 2019.

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Fair Value of Derivative and Other Financial Instruments

3 Months Ended

Mar. 31, 2019

Fair Value of Derivative and Other Financial Instruments [Abstract]

Fair Value of Derivative and Other Financial Instruments

Fair Value of Derivative and Other Financial Instruments

Additional information concerning energy related derivative contracts and other financial instruments is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

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

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.

Beginning January 1, 2018, PNM is exposed to market risk for its 65 MW interest in SJGS Unit 4, which is held as merchant plant as ordered by the NMPRC. PNM has entered into agreements to sell 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 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. PNM passes the sales and purchases through to customers under PNM’s FPPAC.

PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. 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. PNM monitors the market risk of its commodity contracts 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 three months ended March 31, 2019 and the year ended December 31, 2018, 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.

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
	March 31, 2019			December 31, 2018
	(In thousands)
Current assets	$	1,086		$	1,083
Deferred charges	2,265			2,511
	3,351			3,594
Current liabilities	(1,150		)	(1,177		)
Long-term liabilities	(2,265		)	(2,511		)
	(3,415		)	(3,688		)
Net	$	(64	)	$	(94	)

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 $3.3 million at March 31, 2019 and $3.6 million at December 31, 2018 resulting from PNM’s hazard sharing arrangements with Tri-State. The hazard sharing arrangements are net-settled upon delivery. Other amounts that could be offset under master netting agreements were immaterial.

At March 31, 2019 and December 31, 2018, PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at March 31, 2019 and December 31, 2018, amounts posted as cash collateral under margin arrangements were $1.0 million and $1.0 million. At March 31, 2019 and December 31, 2018, obligations to return cash collateral were $0.9 million and $1.0 million. Cash collateral amounts are included in other current assets and other current liabilities on the Condensed 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 insignificant amounts hedged under this plan as of March 31, 2019 and no amounts were hedged under this plan as of December 31, 2018.

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
	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
Electric operating revenues	$	28		$	(10	)
Cost of energy	(28		)	12
Total gain	$	—		$	2

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
March 31, 2019	100,000	(400	)
December 31, 2018	100,000	—

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 March 31, 2019 and December 31, 2018, PNM had no such contracts in a net liability position.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Investment securities are carried at fair value. Investment 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 11). At March 31, 2019 and December 31, 2018, the fair value of investment securities included $308.0 million and $287.1 million for the NDT and $43.6 million and $41.1 million for the mine reclamation trusts.

As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, on January 1, 2018 the Company adopted Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10). Accordingly, on January 1, 2018 PNM recorded an after-tax cumulative effect adjustment of $11.2 million to reclassify unrealized holding gains on equity securities held in the NDT and coal mine reclamation trusts from AOCI to retained earnings on the Condensed Consolidated Balance Sheets. After January 1, 2018, all gains and losses resulting from sales and changes in the fair value of equity securities are recognized in earnings. Under ASU 2016-01, the accounting for available-for-sale debt securities remains essentially unchanged.

Gains and losses recognized on the Condensed Consolidated Statements of Earnings related to investment securities in the NDT and reclamation trusts are presented in the following table.

	Three Months Ended March 31,
	2019		2018
	(In thousands)
Equity securities:
Net gains from equity securities sold	$	1,387	$	2,828
Net gains from equity securities still held	9,602		136
Total net gains on equity securities	10,989		2,964
Available-for-sale debt securities:
Net gains (losses) on debt securities	3,025		(2,676		)
Net gains on investment securities	$	14,014	$	288

The proceeds and gross realized gains and losses on the disposition of securities held in the NDT and coal mine reclamation trusts 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 $3.4 million and $(1.2) million for the three months ended March 31, 2019 and 2018.

	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
Proceeds from sales	$	74,460		$	626,729
Gross realized gains	$	4,189		$	6,021
Gross realized (losses)	$	(3,170	)	$	(4,677	)

The Company has no available-for-sale debt 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 March 31, 2019, the available-for-sale debt securities held by PNM, had the following final maturities:

	Fair Value
	(In thousands)
Within 1 year	$	13,996
After 1 year through 5 years	68,108
After 5 years through 10 years	68,904
After 10 years through 15 years	9,485
After 15 years through 20 years	12,174
After 20 years	45,695
	$	218,362

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. 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 three months ended March 31, 2019 or the year ended December 31, 2018.

For investment securities, Level 2 and Level 3 fair values are provided by fund managers utilizing a pricing service. For Level 2 fair values, 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. Fair values of Level 2 investments in mutual funds are equal to net asset value. Level 3 investments are comprised of corporate term loans. 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. The valuation of Level 3 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. Management of the Company independently verifies the information provided by pricing services.

Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy along with gross unrealized gains on investments in available-for-sale debt securities.

				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)		Unrealized Gains
	(In thousands)
March 31, 2019
Cash and cash equivalents	$	10,339		$	10,339	$	—		$	—
Equity securities:
Corporate stocks, common	36,025			36,025		—			—
Corporate stocks, preferred	8,138			1,854		6,284			—
Mutual funds and other	78,699			78,688		11			—
Available-for-sale debt securities:
U.S. Government	36,153			25,074		11,079			—		$	1,489
International Government	11,577			46		11,531			—		345
Municipals	49,160			—		49,160			—		1,337
Corporate and other	121,472			842		118,543			2,087		5,831
	$	351,563		$	152,868	$	196,608		$	2,087	$	9,002
Commodity derivative assets	$	3,351		$	—	$	3,351		$	—
Commodity derivative liabilities	(3,415		)	—		(3,415		)	—
Net	$	(64	)	$	—	$	(64	)	$	—
December 31, 2018
Cash and cash equivalents	$	11,472		$	11,472	$	—		$	—
Equity securities:
Corporate stocks, common	32,997			32,997		—			—
Corporate stocks, preferred	7,258			1,654		5,604			—
Mutual funds and other	70,777			70,777		—			—
Available-for-sale debt securities:
U.S. Government	29,503			18,662		10,841			—		$	1,098
International Government	8,435			—		8,435			—		90
Municipals	53,642			—		53,642			—		489
Corporate and other	114,158			588		111,414			2,156		923
	$	328,242		$	136,150	$	189,936		$	2,156	$	2,600
Commodity derivative assets	$	3,594		$	—	$	3,594		$	—
Commodity derivative liabilities	(3,688		)	—		(3,688		)	—
Net	$	(94	)	$	—	$	(94	)	$	—

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

	Corporate Debt
	(In thousands)
Balance at December 31, 2018	$	2,156
Actual return on assets sold during the period	(49		)
Actual return on assets still held at period end	54
Purchases	414
Sales	(488		)
Balance at March 31, 2019	$	2,087
Balance at December 31, 2017	$	—
Actual return on assets sold during the period	(3		)
Actual return on assets still held at period end	(11		)
Purchases	2,724
Sales	(359		)
Balance at March 31, 2018	$	2,351

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

					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
March 31, 2019	(In thousands)
PNMR
Long-term debt	$	2,944,241	$	3,023,159	$	—	$	3,023,159	$	—
Other investments	$	299	$	299	$	299	$	—	$	—
PNM
Long-term debt	$	1,706,873	$	1,744,864	$	—	$	1,744,864	$	—
Other investments	$	93	$	93	$	93	$	—	$	—
TNMP
Long-term debt	$	798,941	$	838,705	$	—	$	838,705	$	—
Other investments	$	206	$	206	$	206	$	—	$	—
December 31, 2018
PNMR
Long-term debt	$	2,670,111	$	2,703,810	$	—	$	2,703,810	$	—
Other investments	$	297	$	297	$	297	$	—	$	—
PNM
Long-term debt	$	1,656,490	$	1,668,736	$	—	$	1,668,736	$	—
Other investments	$	91	$	91	$	91	$	—	$	—
TNMP
Long-term debt	$	575,398	$	597,236	$	—	$	597,236	$	—
Other investments	$	206	$	206	$	206	$	—	$	—

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Stock-Based Compensation

3 Months Ended

Mar. 31, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

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. The Company has not awarded stock options since 2010. Certain restricted stock awards are subject to achieving performance or market targets. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

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, awards to employees 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. Awards of restricted stock to non-employee members of the Board are expensed over a one-year vesting period.

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 over the performance period as required service is provided 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. At March 31, 2019, PNMR had unrecognized expense related to stock awards of $6.5 million, which is expected to be recognized over an average of 1.74 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. GAAP requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as operating cash flows when used to reduce income taxes payable.

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:

	Three Months Ended March 31,
Restricted Shares and Performance Based Shares	2019			2018
Expected quarterly dividends per share	$	0.2900		$	0.2650
Risk-free interest rate	2.50		%	2.39		%
Market-Based Shares
Dividend yield	2.59		%	2.96		%
Expected volatility	19.55		%	19.12		%
Risk-free interest rate	2.51		%	2.36		%

The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the three months endedMarch 31, 2019:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2018	166,651		$	32.93	81,000		$	11.94
Granted	114,611		$	36.48	—		$	—
Exercised	(118,427	)	$	30.97	(78,000	)	$	11.92
Forfeited	—		$	—	—		$	—
Expired	—		$	—	—		$	—
Outstanding at March 31, 2019	162,835		$	36.86	3,000		$	12.38

PNMR’s stock-based compensation program provides for performance and market targets through 2021. In February 2019, the Board approved amendments to exclude certain impacts of the Tax Act on performance metrics for the performance periods ending in 2018 and 2019. These amendments did not impact the Company’s calculation of grant date fair values under the plans, but did increase actual achievement levels for the performance period ending in 2018 from below “threshold” levels to below “target” levels and anticipated achievement levels for the performance period ending in 2019 from below “target” levels to the “maximum” level. Included as granted and exercised in the table above are 47,279 previously awarded shares that were earned for the 2016 through 2018 performance measurement period and ratified by the Board in February 2019 (based upon achieving market targets at below “threshold” levels, weighted at 40%, and performance targets at above “target” levels, together weighted at 60%). Excluded from the table above are maximums of 130,302, 146,941, and 135,678 shares for the three-year performance periods ending in 2019, 2020, and 2021 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she was to receive 17,953 of the total shares if PNMR achieved specific performance targets at the end of 2017. The specified performance target was achieved at the end of 2017 and the Board ratified her receiving 17,953 shares in February 2018. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

At March 31, 2019, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $0.1 million with a weighted-average remaining contract life of 1.0 years. At March 31, 2019, 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:

	Three Months Ended March 31,
Restricted Stock	2019		2018
Weighted-average grant date fair value	$	36.48	$	29.03
Total fair value of restricted shares that vested (in thousands)	$	5,314	$	7,162
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)	$	2,582	$	2,711

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Financing

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Financing

Financing

The Company’s financing strategy includes both short-term and long-term borrowings. The Company utilizes short-term revolving credit facilities, as well as cash flows from operations, to provide funds for both construction and operating expenditures. Depending on market and other conditions, the Company will periodically sell long-term debt or enter into term loan arrangements and use the proceeds to reduce borrowings under the revolving credit facilities or refinance other debt. Each of the Company’s revolving credit facilities and term loans contain a single financial covenant that requires the maintenance of a debt-to-capitalization ratio. For the PNMR and PNMR Development agreements, this ratio must be maintained at less than or equal to 70%, and for the PNM and TNMP agreements, this ratio must be maintained at less than or equal to 65%. The Company’s revolving credit facilities and term loans generally also contain 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. Additional information concerning financing activities is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Financing Activities

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 was required to post in connection with permits relating to the operation of the San Juan mine. On March 15, 2019, WSJ LLC acquired the assets of SJCC following the bankruptcy of Westmoreland. WSJ LLC assumed the obligations to PNMR under the letters of credit support (Note 11).

On April 9, 2018, PNMR Development deposited $68.2 million with PNM related to potential transmission network interconnections, which was classified as a cash inflow from financing activities on PNM’s Condensed Consolidated Statements of Cash Flows in the second quarter of 2018. PNM used the deposit to repay intercompany borrowings. PNM is required to pay interest to PNMR Development to the extent work under the interconnections has not been performed. During the three months ended March 31, 2019, PNM recognized $0.9 million of interest expense under the agreement. At March 31, 2019, PNM’s remaining obligation under the interconnection agreement with PNMR Development of $68.2 million, excluding unpaid interest, is reflected in other deferred credits on PNM’s Condensed Consolidated Balance Sheets. As required by GAAP, all intercompany transactions related to this deposit have been eliminated on PNMR’s Condensed Consolidated Financial Statements.

On January 18, 2019, PNM entered into a $250.0 million term loan agreement (the “PNM 2019 Term Loan”) among PNM, the lenders identified therein, and U.S. Bank N.A., as administrative agent. PNM used the proceeds of the PNM 2019 Term Loan to repay the PNM 2017 Term Loan, to reduce short-term borrowings under the PNM Revolving Credit Facility, and for general corporate purposes. The PNM 2019 Term Loan bears interest at a variable rate and must be repaid on or before July 17, 2020.

On February 26, 2019, TNMP entered into the TNMP 2019 Bond Purchase Agreement with institutional investors for the sale of $305.0 million aggregate principal amount of four series of TNMP first mortgage bonds (the “TNMP 2019 Bonds”) offered in private placement transactions. TNMP issued $225.0 million of TNMP 2019 Bonds on March 29, 2019 and used the proceeds to repay TNMP’s $172.3 million9.50% first mortgage bonds at their maturity on April 1, 2019, as well as to repay borrowings under the TNMP Revolving Credit Facility and for other general corporate purposes. TNMP will issue the remaining $80.0 million of TNMP 2019 Bonds on or before July 1, 2019 and will use the proceeds from that issuance to repay borrowings under the TNMP Revolving Credit Facility and for other general corporate purposes. The issuance of the remaining TNMP 2019 Bonds is subject to the satisfaction of customary conditions, and the TNMP 2019 Bonds are subject to continuing compliance with the representations, warranties and covenants of the TNMP 2019 Bond Purchase Agreement. The terms of the TNMP 2019 Bond Purchase Agreement include customary covenants, including a covenant that requires TNMP to maintain a debt-to-capitalization ratio of less than or equal to 65%, customary events of default, a cross-default provision, and a change-of-control provision. TNMP will have the right to redeem any or all of the TNMP 2019 Bonds prior to their respective maturities, subject to payment of a customary make-whole premium. In accordance with GAAP, borrowings under the $172.3 million9.50% TNMP first mortgage bonds are reflected as being long-term in the Condensed Consolidated Balance Sheets at December 31, 2018 since TNMP demonstrated its intent and ability to re-finance the agreement on a long-term basis. These bonds are reflected in current maturities of long-term debt on the Condensed Consolidated Balance Sheets at March 31, 2019 since the proceeds from the issuance of $225.0 million of TNMP 2019 Bonds, net of amounts used to repay short-term debt, are reflected in cash and cash equivalents.

Information concerning the funding dates, maturities and interest rates on the TNMP 2019 Bonds issued in March 2019 and to be issued on or before July 1, 2019 is as follows:

Funding Date	Maturity Date	Principal Amount		Interest Rate
		(In millions)
March 29, 2019	March 29, 2034	$	75.0	3.79	%
March 29, 2019	March 29, 2039	75.0		3.92	%
March 29, 2019	March 29, 2044	75.0		4.06	%
		225.0
July 1, 2019	July 1, 2029	80.0		3.60	%
		$	305.0

At March 31, 2019, variable interest rates were 3.29% on the $50.0 million PNMR 2018 Two-Year Term Loan, which matures in December 2020, 3.13% on the $250.0 million PNM 2019 Term Loan, which matures in July 2020, 3.20% on the $35.0 million TNMP 2018 Term Loan, which matures in July 2020, and 3.30% on the $90.0 million PNMR Development Term Loan, which matures in November 2020.

Short-term Debt and Liquidity

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. Both facilities currently expire on October 22, 2023 but contain options to be extended through October 2024, subject to approval by a majority of the lenders. One lender whose commitment was $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. On April 25, 2019, a new lender assumed the commitments of the non-extending lender under the PNMR and PNM Revolving Credit Facilities. PNM also has the $40.0 million PNM 2017 New Mexico Credit Facility that expires on December 12, 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 and matures on September 23, 2022.

On February 22, 2019, PNMR Development amended its $24.5 million revolving credit facility to increase the capacity to $25.0 million and to extend the term until February 24, 2020. The PNMR Development Revolving Credit 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 uses the facility to finance its participation in NMRD and for other activities.

Short-term debt outstanding consisted of:

	March 31,		December 31,
Short-term Debt	2019		2018
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	—	$	32,400
PNM 2017 New Mexico Credit Facility	—		10,000
	—		42,400
TNMP Revolving Credit Facility	—		17,500
PNMR:
PNMR Revolving Credit Facility	62,200		20,000
PNMR 2018 One-Year Term Loan	150,000		150,000
PNMR Development Revolving Credit Facility	11,600		6,000
	$	223,800	$	235,900

At March 31, 2019, the weighted average interest rate was 3.74% for the PNMR Revolving Credit Facility, 3.24% for the PNMR 2018 One-Year Term Loan, and 3.49% for the PNMR Development Revolving Credit Facility.

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $4.7 million, $2.5 million, and $0.7 million at March 31, 2019 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of March 31, 2019 and December 31, 2018, TNMP had zero and $0.1 million of intercompany borrowings from PNMR, PNM had zero and $19.8 million of intercompany borrowings from PNMR, and PNMR Development had $3.1 million and zero of intercompany borrowings from PNMR.

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 for three separate tranches, each of $50.0 million, of its variable rate debt. These hedge agreements are accounted for as cash flow hedges. These hedge agreements had fair values aggregating $1.4 million at March 31, 2019 that is included in other deferred charges and $1.0 million at December 31, 2018 that is included in other current assets on the Condensed Consolidated Balance Sheets. As discussed in Note 3, changes in the fair value of the cash flow hedge are deferred in AOCI and amounts reclassified to the Condensed Consolidated Statement of Earnings are recorded in interest charges. 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. On January 1, 2019, the Company adopted Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. Adoption of the updated standard did not have a significant impact on these cash flow hedges.

At May 3, 2019, PNMR, PNM, TNMP, and PNMR Development had availability of $239.4 million, $397.5 million, $45.7 million, and $9.9 million under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $40.0 million of availability under the PNM 2017 New Mexico Credit Facility. Total availability at May 3, 2019, on a consolidated basis, was $732.5 million for PNMR. As of May 3, 2019, PNM and TNMP had no borrowings from PNMR under their intercompany loan agreements. At May 3, 2019, PNMR, PNM, and TNMP had invested cash of $0.9 million, $9.0 million, and none.

The Company’s debt arrangements have various maturities and expiration dates. As discussed above, on February 26, 2019 TNMP entered into the TNMP 2019 Bond Purchase Agreement providing for the issuance of an aggregate of $305.0 million of TNMP 2019 Bonds. TNMP issued $225.0 million of the TNMP 2019 Bonds on March 29, 2019 and used a portion of the proceeds from that issuance to repay TNMP’s $172.3 million9.50% first mortgage bonds at their maturity on April 1, 2019. TNMP will issue the remaining $80.0 million of TNMP 2019 Bonds on or before July 1, 2019 and will use the proceeds from that issuance to repay borrowings under the TNMP Revolving Credit Facility and for other general corporate purposes. In addition, the $150.0 million PNMR 2018 One-Year term loan will mature in December 2019. The Company has no other long-term debt due through March 31, 2020. Additional information on debt maturities is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

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Pension and Other Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Pension and Other Postretirement Benefit Plans

Pension and Other Postretirement Benefit Plans

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. In accordance with GAAP, the Company presents the service cost component of its net periodic benefit costs in administrative and general expenses and the non-service costs components in other income (deductions), net of amounts capitalized or deferred to regulatory assets and liabilities, on the Condensed Consolidated Statements of Earnings. PNM and TNMP receive a regulated return on the amounts funded for pension and OPEB plans in excess of accumulated periodic cost or income to the extent included in retail rates (a “prepaid pension asset”).

Additional information concerning pension and OPEB plans is contained in Note 11 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Annual net periodic benefit cost for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year.

PNM Plans

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

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2019			2018			2019			2018			2019		2018
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	13		$	21		$	—	$	—
Interest cost	6,294			6,068			829			860			162		155
Expected return on plan assets	(8,527		)	(8,672		)	(1,318		)	(1,353		)	—		—
Amortization of net (gain) loss	3,880			4,087			169			588			79		90
Amortization of prior service cost	(241		)	(241		)	(99		)	(416		)	—		—
Net periodic benefit cost	$	1,406		$	1,242		$	(406	)	$	(300	)	$	241	$	245

PNM did not make any contributions to its pension plan trust in the three months ended March 31, 2019 and 2018 and does not anticipate making any contributions to the pension plan in 2019-2021, but expects to contribute $1.3 million in 2022 and $22.9 million in 2023, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.2% to 4.6%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made no contributions to the OPEB trust in the three months ended March 31, 2019 and 2018. PNM does not expect to make any contributions to the OPEB trust in 2019-2023.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $0.5 million in the three months ended March 31, 2019 and 2018 and are expected to total $1.5 million during 2019 and $5.6 million for 2020-2023.

TNMP Plans

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

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2019			2018			2019			2018			2019		2018
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	13		$	33		$	—	$	—
Interest cost	672			656			113			119			8		7
Expected return on plan assets	(967		)	(991		)	(129		)	(135		)	—		—
Amortization of net (gain) loss	235			272			(110		)	(56		)	4		4
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost	$	(60	)	$	(63	)	$	(113	)	$	(39	)	$	12	$	11

TNMP did not make any contributions to its pension plan trust in the three months ended March 31, 2019 and 2018 and does not anticipate making any contributions in 2019-2023, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.2% to 4.6%. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions of zero and $0.3 million to the OPEB trust in the three months ended March 31, 2019 and 2018. TNMP does not expect to make contributions to the OPEB trust during the period 2019-2023. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three months ended March 31, 2019 and 2018 and are expected to total $0.1 million during 2019 and $0.3 million in 2020-2023.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. In addition, the Company 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 12) 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. 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 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.

Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Commitments and Contingencies Related to the Environment

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 the DOE entered into a settlement agreement that establishes a process for the payment of claims for costs incurred through December 31, 2019. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. PNM records estimated claims on a quarterly basis. The benefit from the claims is passed through to customers under the FPPAC to the extent applicable to NMPRC regulated operations.

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 nuclear fuel is consumed. At March 31, 2019 and December 31, 2018, PNM had a liability for interim storage costs of $12.5 million and $12.4 million, which is 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.

The Energy Transition Act

On March 22, 2019, the Governor signed into New Mexico state law Senate Bill 489, known as the Energy Transition Act (“ETA”). The ETA becomes effective as of June 14, 2019 and sets a statewide standard that requires investor-owned electric utilities to have specified percentages of their electric-generating portfolios be provided from renewable and zero-carbon generating resources. Prior to the enactment of the ETA, the REA established a mandatory RPS requiring utilities to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also amends sections of the REA to allow for the recovery of undepreciated investments and decommissioning costs related to qualifying EGUs that the NMPRC has required be removed from retail jurisdictional rates, provided replacement resources to be included in retail rates have lower or zero-carbon emissions. The ETA requires the NMPRC to review and approve utilities’ annual renewable portfolio plans to ensure compliance with the RPS. The ETA also directs the New Mexico Environmental Improvement Board to adopt standards of performance that limit CO₂ emissions to no more than 1,100 lbs. per MWh beginning January 1, 2023 for new or existing coal-fired EGUs with original installed capacities exceeding 300 MWs.

The ETA provides for a transition from fossil-fuel generation resources to renewable and other carbon-free resources through certain provisions relating to the abandonment of coal-fired generating facilities. These provisions include the use of “energy transition bonds,” which are designed to be highly rated bonds that can be issued by qualifying utilities to finance certain costs of abandoning coal-fired facilities that are retired prior to January 1, 2023, for facilities operated by a “qualifying utility,” or prior to January 1, 2032 for facilities that are not operated by the qualifying utility. The amount of energy transition bonds that can be issued to recover abandonment costs is limited to the lesser of $375.0 million or 150% of the undepreciated investment of the facility as of the abandonment date. Proceeds provided by energy transition bonds must be used only for purposes related to providing utility service to customers and to pay “financing costs” (as defined by the ETA). These costs may include plant decommissioning and coal mine reclamation costs provided those costs have not previously been recovered from customers or disallowed by the NMPRC or by a court order. Proceeds from energy transition bonds may also be used to fund severances for employees of the retired facility and related coal mine and to promote economic development, education and job training in areas impacted by the retirement of the coal-fired facilities. Energy transition bonds must be issued under an NMPRC approved financing order, are secured by “energy transition property,” are non-recourse to the issuing utility, and must be repaid by a non-bypassable charge paid by all customers of the issuing utility. These customer charges are subject to an adjustment mechanism designed to provide for timely and complete payment of principal and interest due under the energy transition bonds.

The ETA also provides that utilities must obtain NMPRC approval of competitively procured replacement resources. In determining whether to approve replacement resources, the NMPRC must give preference to resources with the least environmental impacts, those with higher ratios of capital costs to fuel costs, and those able to reduce the cost of reclamation and use for lands previously mined within the county of the EGU to be abandoned. Replacement resources will be subject to local taxes or equivalent payments in lieu of taxes and are defined to mean up to 450 MW of nameplate capacity, provided such resources are located in the same school district as the abandoned facility, are necessary to maintain reliable service, and are in the public interest as determined by the NMPRC. The ETA also provides for the procurement of energy storage facilities and gives utilities discretion to maintain and control these systems to ensure reliable and efficient service.

The effectiveness of the ETA will have a significant impact on PNM’s future generation portfolio, including PNM’s planned retirement of SJGS in 2022. See December 2018 Compliance Filing below. PNM cannot predict the full impact of the ETA or the outcome of its potential future financing and generating resource abandonment and replacement resource filings with the NMPRC.

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 was demonstrated that the emissions from these sources caused or contributed to visibility impairment in any Class I area, then BART must have been installed by the beginning of 2018. For all future SIP planning periods, 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. On December 20, 2018, EPA released a new guidance document on tracking visibility progress for the second planning period. EPA is allowing states discretion to develop SIPs that may differ from EPA’s guidance as long as they are consistent with the CAA and other applicable regulations. SIPs for the second compliance period are due in July 2021. EPA’s decision to revisit the 2017 rule is not a determination on the merits of the issues raised in the petitions. PNM is evaluating the potential impacts of these matters.

SJGS

December 2018 Compliance Filing –As discussed in Note 16 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, in December 2015 PNM received NMPRC approval for a plan to comply with the EPA regional haze rule at SJGS. Among other things, the NMPRC’s December 2015 order required that, no later than December 31, 2018, PNM make a filing with the NMRPC to determine the extent to which SJGS should continue serving PNM’s customers’ needs after June 30, 2022, including PNM’s recommendation and supporting testimony and exhibits (the “December 2018 Compliance Filing”). The December 2018 Compliance Filing was required to be made before PNM entered into a binding commitment for post-2022 coal supply but after PNM received firm pricing and other terms for the supply of coal at SJGS, unless PNM did not intend to pursue an agreement for post-2022 coal supply at SJGS. The NMPRC’s December 2015 order also indicated that, if SJGS Unit 4 is abandoned with undepreciated investment on PNM’s books, PNM is prohibited from recovering the undepreciated investment of its 132 MW interest and required that PNM’s 65 MW interest in SJGS Unit 4 be treated as excluded merchant plant. PNM is currently depreciating all its investments in SJGS through 2053, which reflects the period of time over which the NMPRC has authorized PNM to recover its investment in SJGS from New Mexico retail customers.

PNM submitted the December 2018 Compliance Filing to the NMPRC on December 31, 2018 indicating that, consistent with the conclusions reached in PNM’s 2017 IRP (Note 12), PNM’s customers would benefit from the retirement of PNM’s share of SJGS after the current SJGS CSA expires in mid-2022. The December 2018 Compliance Filing also indicates that, pursuant to the terms of the agreements governing SJGS, all of the SJGS owners except for Farmington have provided written notice that they do not intend to extend the SJGS operating agreements beyond their June 30, 2022 expiration dates, and that PNM has provided written notice to SJCC that PNM does not intend to extend the SJGS CSA beyond June 30, 2022 or to negotiate a new coal supply agreement on behalf of the other SJGS participants. The December 2018 Compliance Filing also requested the NMPRC accept the filing as compliant with the December 2015 order and indicated that PNM anticipates it will have sufficient information by the end of the second quarter of 2019 to support a consolidated application seeking NMPRC approval to retire PNM’s share of SJGS in 2022 and for approval of CCNs, PPAs, or other applicable approvals, for replacement capacity resources. On January 10, 2019, the NMPRC opened a docket to determine whether the NMPRC should grant PNM’s request to accept the December 2018 Compliance Filing and take no further action pending PNM submitting a formal consolidated abandonment and replacement resources application, or whether the NMPRC should immediately establish a formal procedural schedule regarding the abandonment of SJGS. The NMPRC received responses from parties regarding the initial order and, on January 30, 2019, approved an order initiating a proceeding and requiring PNM to submit an application for the abandonment of PNM’s share of SJGS by March 1, 2019. On February 7, 2019, PNM filed a motion requesting the NMPRC vacate the January 30, 2019 order and extend the deadline for PNM’s abandonment filing until the end of the second quarter of 2019, which was deemed denied. On February 27, 2019, PNM filed a petition with the NM Supreme Court stating that the requirements of the January 30, 2019 order exceed the NMPRC’s authority by, among other things, mandating PNM to make a filing that is legally voluntary, and that the order is contrary to NMPRC precedent which requires abandonment applications to also include identified replacement resources and other information that would not be available to PNM by March 1, 2019. PNM’s petition also requested the NM Supreme Court stay the January 30, 2019 order until after June 14, 2019. On March 1, 2019, the NM Supreme Court granted a temporary stay of the NMPRC’s order to consider the merits of PNM’s petition after receiving responses.  On March 19, 2019, the NMPRC and NEE filed responses supporting the NMPRC’s authority to order PNM to initiate a proceeding. Other parties to the case filed responses supporting a stay of the NMPRC’s order and indicating that the abandonment filing should be subject to recently enacted changes in New Mexico state law. See additional discussion of the ETA above. PNM cannot predict the outcome of this matter.

GAAP requires that long-lived assets be tested for impairment when events or changes in circumstances indicate that their carrying value may not be recoverable. The test must consider only those cash flows that are directly associated with the long-lived asset, or group of assets, and requires the evaluation be performed at the lowest level for which identifiable cash flows are largely independent of other cash flows within the asset group. As of December 31, 2018, PNM evaluated the events surrounding its future participation in SJGS and determined that it is more likely than not that PNM’s share of SJGS will be retired in 2022. As a result, PNM performed an impairment analysis that assumed SJGS would not continue to operate through 2053, as previously approved by the NMPRC. PNM’s impairment analysis indicated that, pursuant to the NMPRC’s December 16, 2015 order, PNM’s undepreciated 132 MW interest in SJGS Unit 4 at June 30, 2022 will not be recovered from customers; that the estimated future cash flows expected to result from the operation of SJGS Unit 4 through June 30, 2022 are not sufficient to provide for recovery of PNM’s 65 MW merchant interest in the facility; and that it is unlikely PNM will be able to sell or transfer its interests in SJGS to third parties at amounts sufficient to provide for their recovery. As a result, as of December 31, 2018, PNM recorded a pre-tax impairment of its investment in SJGS of approximately $35.0 million, which is reflected as regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings in the 2018 Annual Reports on Form 10-K. This amount includes the entire $11.9 million carrying value of PNM’s 65 MW interest in SJGS Unit 4 as of December 31, 2018 and $23.1 million of estimated undepreciated investments in PNM’s 132 MW jurisdictional interest as of June 30, 2022 that will not be recovered from customers. The carrying value of PNM’s remaining undepreciated investments in SJGS, which PNM will seek to recover from customers in the event of an early retirement of the facility, is $371.6 million as of March 31, 2019. See additional discussion regarding the increase in PNM’s estimated liability for coal mine reclamation below.

The December 2018 Compliance Filing and the 2017 IRP are not final determinations of PNM’s future generation portfolio.  Retiring PNM’s share of SJGS will require future NMPRC approval. PNM will also be required to obtain NMPRC approval of replacement power resources through CCN, PPA, or other applicable filings. The financial impact of an early retirement of SJGS and the NMPRC approval process are influenced by many factors outside of PNM’s control, including the economic impact of a potential SJGS abandonment filing on the area surrounding that plant and the related mine, as well as the overall political and economic conditions of New Mexico. Other items that impact the economic viability of SJGS include the financial impact of climate change regulation or legislation, other environmental regulations, the result of litigation, and other business considerations or the ability or willingness of individual participants to continue participation in the plant. Furthermore, PNM’s application for the abandonment of SJGS, related financing, and for associated replacement resources would be significantly influenced by the requirements of the ETA. PNM will seek full recovery of its remaining undepreciated investments and other costs necessary to retire the facility and for replacement resources in that filing.

NEE Complaint – 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. On January 31, 2018, NEE filed a motion asking the NMPRC to investigate whether PNM’s relationship with WSJ, in light of Westmoreland’s financial condition, could be harmful to PNM’s customers. PNM responded requesting the NMPRC deny the motion and that NEE’s prior complaint be dismissed. On May 23, 2018, PNM filed its response to the NMPRC staff’s comments requesting additional information about the financing and noting that the Westmoreland Loan was paid in full on May 22, 2018. On October 11, 2018, PNM filed a supplemental response notifying the NMPRC that Westmoreland had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code on October 9, 2018. PNM’s supplemental response indicated Westmoreland had agreed to terms with its secured creditors that allowed it to continue to fund normal-course operations and to continue to serve its customers during the course of the bankruptcy case. As discussed in Note 6, on March 15, 2019, Westmoreland announced that it had emerged from Chapter 11 bankruptcy as a privately held company owned and operated by a group of its former creditors. Under the reorganization, all the assets of SJCC were sold to WSJ LLC. The March 15, 2019 announcement indicated that mining operations will continue in the normal course of business. As successor entity to SJCC, WSJ LLC assumed all rights and obligations of Westmoreland including obligations to PNM under the SJGS CSA. The NMPRC has taken no further action on NEE’s complaints. PNM cannot predict the outcome of these matters.

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 dismissal in the United States Court of Appeals for the Ninth Circuit on November 9, 2017, and the court granted their subsequent motion to expedite the appeal. Oral arguments for the appeal were held on March 7, 2019. 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 NSPS 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, 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. In a separate but related action, on December 18, 2017, EPA released an advanced NOPR addressing GHG guidelines for existing electric utility generating units. On August 31, 2018, EPA published a proposed rule, which is informally known as the Affordable Clean Energy rule, to replace the Clean Power Plan. The proposed Affordable Clean Energy rule, among other things, would establish guidelines that replace the “outside-the-fenceline” control measures and specific numerical emission rates for existing EGUs. These measures are replaced with a list of “candidate technologies” for heat rate improvement measures, which include both technologies and operational changes that EPA has identified as Best System of Emission Reduction (“BSER”). States would determine which of the candidate technologies to apply to each coal-fired unit and establish standards of performance based on the degree of emission reduction achievable through application of the selected BSER.  States will have three years from when the rule is finalized to submit a plan to EPA. EPA will then have one year to determine if each proposed plan is acceptable. If states do not submit a plan, or if a state’s plan is not acceptable, EPA will develop a federal plan for the state to implement.  EPA is also proposing revisions to the NSR program that would provide coal-fired power plants more latitude to make efficiency improvements consistent with BSER without triggering NSR permit requirements. Comments on the proposed Affordable Clean Energy rule were due to EPA by October 31, 2018.

The proposed Affordable Clean Energy rule and the proposed 2015 federal plan released concurrently with the Clean Power Plan are 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 proposed Affordable Clean Energy rule or the Clean Power Plan, should it ultimately be sustained, on the Navajo Nation. In addition, in the proposed 2015 federal plan, EPA included a finding “that it is necessary or appropriate” to implement a section 111(d) federal plan for affected EGUs located in Native American lands. APS and PNM filed separate comments with EPA on EPA’s draft 2015 federal plan 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 if the Affordable Clean Energy rule, the Clean Power Plan, or other future GHG reduction rulemaking are ultimately implemented and EPA determines that a federal plan is necessary or appropriate for the Navajo Nation.

On December 20, 2018, EPA published in the Federal Register a proposed rule that would revise the carbon pollution standards rule published in October 2015 for fossil fueled power plants. The proposed rule would revise the standards for coal-fired EGUs based on a revised BSER determination that would result in less stringent CO₂ emission performance standards for new, reconstructed, and modified fossil-fueled power plants. EPA is not proposing any changes nor reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. Comments on the proposal were due on March 18, 2019.

PNM’s review of the GHG emission reductions standards under the proposed Affordable Clean Energy rule, the revised proposed Carbon Pollution Standards rule, and the Clean Power Plan is ongoing and the assessment of its impacts will depend on the proposed repeal of the Clean Power Plan, promulgation of the Affordable Clean Energy rule and the revised proposed Carbon Pollution Standards rule, other future GHG reduction rulemaking, litigation of any final rule, and other actions the Trump Administration is taking through judicial and regulatory proceedings. As discussed above, SJGS and Four Corners may also be required to comply with additional GHG restrictions issued by the New Mexico Environmental Improvement Board pursuant to the recently enacted ETA. 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 reasonably anticipated to endanger public health or welfare. 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 standard while retaining the annual standards for NOx and SO₂ and the 24-hour SO₂ standard. EPA also updated the final particulate matter standard in 2012 and updated the ozone standard in 2015.

NOx Standard – On April 18, 2018, EPA published the final rule to retain the current primary health-based NOx standards of which NO₂ is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO₂ standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018.

SO₂ Standard – 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. This characterization would result in these areas being designated as attainment, nonattainment, or unclassifiable 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 imposed deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO₂ emissions. The settlement resulted from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree required, among other things, that EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule by December 2020.  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 its formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO₂ standard. On June 27, 2018, NMED submitted the first annual report for SJGS as required by the Data Requirements Rule. The report recommends that no further modeling is warranted at this time due to decreased SO₂ emissions.

On February 25, 2019, EPA announced its final decision to retain without changes the primary health-based NAAQS for SOx. Specifically, EPA will retain the current 1-hour standard for SO₂, which is 75 parts per billion (“ppb”), based on the 3-year average of the 99th percentile of daily maximum 1-hour SO₂ concentrations.  SO₂ is the most prevalent SOx compound and is used as the indicator for the primary SOx NAAQS.

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 required the installation of SNCRs. The revised permit also requires the reduction of SO₂ emissions 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, SO_2, and particulate matter. These reductions 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.

Ozone Standard – On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 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 important 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 for ozone, which states used to determine their initial designation recommendations by October 1, 2016. NMED published its 2015 Ozone NAAQS Designation Recommendation Report on September 2, 2016. In New Mexico, EPA 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 NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. According to NMED’s website, “If emissions from Mexico keep New Mexico from meeting the standards, the New Mexico area could remain 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, San Juan County, New Mexico, where SJGS and Four Corners are located, is designated as attainment/unclassifiable. EPA designated a small area in Dona Ana County as marginal non-attainment.  On April 30, 2018, EPA completed additional area designations for the 2015 ozone standards. In a related matter, EPA published a final rule on March 9, 2018 establishing air quality thresholds that define the classifications assigned to all non-attainment areas for ozone NAAQS. The final rule also establishes the timing of attainment dates for each non-attainment area classification, which are marginal, moderate, serious, severe, or extreme. The rule became effective May 8, 2018.

NMED is required to submit an infrastructure and transport SIP that provides the basic air quality management program to implement the revised ozone standard. This plan is generally due within 36 months from the date the NAAQS is promulgated. The NMED has published a proposed certification that New Mexico currently has an adequate, federally-approved SIP that addresses elements of the CAA Section 110(a)(2) infrastructure SIP, as applicable to the 2015 ozone NAAQS. The purpose of the proposed certification is to confirm to EPA that New Mexico has the required “infrastructure” in place under the current SIP to implement, maintain, and enforce the revised 2015 ozone NAAQS. Comments on the proposed certification were due by October 29, 2018. State ozone attainment plans are generally due within five to six years from the date of the ozone NAAQS promulgation and are planned for submittal in 2020 and 2021.

PNM does not believe there will be material impacts to its facilities as a result of NMED’s non-attainment 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, PNM is unable to predict what impact the adoption of these standards may have on Four Corners. PNM cannot predict the outcome of this matter.

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 challenged several unrelated mining plan modification approvals, which were each separately approved by OSM.  WEG alleged 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 sought 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 concerned 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 NM District Court. 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 was made available in May 2018 and was subject to a public comment period that ended on July 9, 2018. The Notice of Availability for the final EIS was published in the Federal Register and became available on the OSM website on March 15, 2019. NEPA requires OSM to identify a preferred alternative in the final EIS and prepare a recommendation to the Assistant Secretary of Land and Minerals Management. OSM has selected a plan that would allow for continued mining that would extend beyond 2022 as the preferred alternative based on the impact analysis in the EIS. On May 1, 2019, OSM published its Record of Decision, which would allow for continued mining in the underground mine in annual quantities similar to those being currently being provided.  The OSM’s Record of Decision is subject to additional review and approval.  PNM cannot predict the outcome of this matter.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Nation and is held under easements granted by the federal government, as well as agreements with the Navajo Nation which grant each of the owners the right to operate on the site. 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 became effective October 14, 2014.

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

The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is 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.

On May 23, 2018, several environmental groups sued EPA Region IX in the United States Court of Appeals for the Ninth Circuit Court over EPA’s failure to timely reissue the Four Corners NPDES permit. The petitioners asked the court to issue a writ of mandamus compelling EPA Region IX to take final action on the pending NPDES permit by a reasonable date. EPA subsequently reissued the NPDES permit on June 12, 2018. The permit did not contain conditions related to the cooling water intake structure rule as EPA determined that the facility has achieved BTA for both impingement and entrainment by operating a closed-cycle recirculation system and no additional conditions are necessary. On July 16, 2018, several environmental groups filed a petition for review with the EPA’s Environmental Appeals Board concerning the reissued permit. The environmental groups alleged that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning certain revised effluent limitation guidelines, existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. On December 19, 2018, EPA withdrew the Four Corners NPDES permit in order to examine issues raised by the environmental groups. Withdrawal of the permit moots the appeal pending before the Environmental Appeals Board. The EPA’s Environmental Appeals Board thereafter dismissed the environmental groups’ appeal. EPA has indicated that, depending on the amount of public comments received concerning the permit proposal, it anticipates taking final action on a new NPDES permit by August 2019. Four Corners will continue to operate under the 2001 NPDES permit. PNM cannot predict the outcome of this matter or whether reconsideration will have a material impact on PNM’s financial position, results of operations or cash flows.

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 or revised NPDES permit.

On September 18, 2017, EPA published a final rule for postponement of certain compliance dates, which have not yet passed for the Effluent Limitations Guidelines rule, consistent with the EPA’s decision to grant reconsideration of that rule. The 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, although the new deadlines have been challenged in court.

The Effluent Limitations Guidelines rule was challenged in the U.S. Court of Appeals for the Fifth Circuit by numerous parties. On April 12, 2017, EPA signed a notice indicating its intent to reconsider portions of the rule and, on August 22, 2017, the Fifth Circuit issued an order severing the issues under reconsideration and holding the case in abeyance as to those issues. However, the court allowed challenges to other portions of the rule to proceed. On April 12, 2019, the Fifth Circuit granted those challenges and issued an opinion vacating several portions of the rule, specifically those related to legacy wastewater and leachate, for which the court deemed the standards selected by the EPA arbitrary and capricious.

Because SJGS is zero discharge for wastewater and is not required to hold a NPDES permit, it is expected that minimal to no requirements will be imposed. Reeves Station, a PNM-owned gas-fired generating station, discharges cooling tower blowdown to a publicly owned treatment plant and holds an NPDES permit. It is expected that minimal to no requirements will be imposed at Reeves Station.

EPA reissued an NPDES permit for Four Corners on June 12, 2018. EPA had determined that the guidelines in the 2015 rule are not applicable to this permit because the effective dates of the 2015 effluent guidelines rule were extended. On December 19, 2018, EPA withdrew the Four Corners NPDES permit in order to examine issues raised by several environmental groups. Four Corners will continue to operate under the 2001 NPDES permit. See Cooling Water Intake Structures above. 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, during the next NPDES permit renewal for Four Corners, which will be in 2023. PNM is unable to predict the outcome of these matters or a range of the potential costs of compliance.

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

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.  However, the renewed discharge permit requires that PNM conduct more frequent monitoring than originally anticipated, which resulted in an insignificant increase to the project cost estimate as of December 31, 2018.

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 monitoring activities conducted under the CAF to NMED on October 3, 2016. PNM completed all CAF-related work associated with the monitoring plan and received NMED’s approval. PNM’s contractor prepared a scope of work, which PNM and NMED approved, for the installation of additional monitoring wells and additional sampling of certain existing monitoring wells at the site. These activities were completed in June 2018. PNM’s contractor has commenced the next phase of work which includes the installation of up to 38 additional monitoring wells. Work is expected to be completed in mid-2019. Qualified costs of this work are eligible for payment through the CAF.

On March 28, 2019, PNM received notice from NMED that an abatement plan is required with respect to the site to address concentrations of previously identified compounds found in the groundwater. The abatement plan would include an investigation to define site conditions and provide data necessary to select and design an abatement option. PNM must submit its abatement plan to NMED by May 27, 2019 but has requested an extension to June 25, 2019. Under NMED regulations, NMED and PNM are required to publish information summarizing the source and magnitude of the pollution. NMED may also hold a public hearing if there is sufficient public interest.

PNM is unable to predict the outcome of these matters.

Coal Combustion Residuals Waste Disposal

CCRs consisting of fly ash, bottom ash, and gypsum generated from coal combustion and emission control equipment at SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCR impoundments or landfills. The NMMMD currently regulates mine reclamation activities at the San Juan mine, including placement of CCRs in the surface mine pits, with federal oversight by the OSM. APS disposes of CCRs in 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.

EPA’s final coal ash rule, which became effective on October 19, 2015, included a non-hazardous waste determination for coal ash. The rule sets minimum criteria for existing and new CCR landfills and existing and new CCR 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 of RCRA, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the 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 requirements.

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 CCR rules under Subtitle D. Among other things, the WIIN Act provides for the establishment of state and EPA permit programs for CCRs, provides flexibility for states to incorporate the EPA final rule for CCRs 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 CCR 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 CCR 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 CCR provisions of the WIIN Act. There is no timeline for establishing either state or federal permitting programs. APS has sought 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 CCR regulations based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCRs, which were premised in part on the provisions of the WIIN Act. In light of the WIIN Act and the petitions for rulemaking, EPA is considering making additional changes to the CCR 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 CCR regulations and pursuant to an order issued by the DC Circuit, EPA and the industry groups argued the court should postpone adjudication until EPA completes the reconsideration process for the affected provision.

Pursuant to a June 24, 2016 order by the DC Circuit in litigation by industry and environmental groups challenging EPA’s CCR regulations, EPA is required to complete a rulemaking proceeding by June 2019 to address specific technical issues. On March 15, 2018, EPA proposed its Phase I Remand Rule that includes potential revisions to provide site-specific, risk-based tailoring of groundwater monitoring, corrective action and location restriction requirements of the CCR rule. EPA published the final rule on July 30, 2018. According to EPA, the July 30, 2018 rule constitutes “Phase One, Part One” of its ongoing reconsideration and revision of the April 17, 2015 coal ash rule. The final rule includes two types of revisions. The first revision extends the deadline to allow EGUs with unlined impoundments or that fail to meet the uppermost aquifer requirement to continue to receive coal ash until October 31, 2020. The second revision authorizes a “Participating State Director” or EPA, in lieu of a professional engineer, to approve suspension of groundwater monitoring and to issue certifications related to the location restrictions, design criteria, groundwater monitoring, remedy selection and implementation. The revisions also modify groundwater protection standards for certain constituents, which include cobalt, molybdenum, lithium, and lead without a maximum contamination level. EPA indicated that provisions in the March 2018 rule that are not addressed in the July 2018 final rule will be addressed in a subsequent rulemaking.

On August 21, 2018, the DC Circuit Court of Appeals issued its decision in the CCR litigation. The court denied EPA’s request to hold the case in abeyance; remanded the industry group’s challenges to the regulation of certain on-site CCR piles; denied relief for the remaining industry group’s claims, including the challenge to EPA’s authority to regulate inactive surface impoundments; and found for the environmental groups on their challenges to the ability of unlined impoundments to continue operating, the classification of certain unlined impoundments as “lined” units, and EPA’s failure to regulate legacy ponds. It remains unclear how the DC Circuit Court of Appeals decision will impact Four Corners as EPA has not yet taken regulatory action on remand to revise its CCR regulations consistent with the court’s order.

Based on this decision, on December 17, 2018, certain environmental groups filed an emergency motion with the D.C. Circuit to stay or summarily vacate EPA’s July 17, 2018 final rule extending the closure-initiation deadline for certain unlined CCR surface impoundments until October 2020. In response, EPA filed a motion to remand but not vacate that deadline extension regulation. On March 13, 2019, the court granted EPA’s motion for a voluntary remand without vacatur. As a result, the “Phase One, Part One” rule will remain in place while EPA reconsiders the rule on remand and continues its ongoing revisions to the CCR rule. This means that the October 31, 2020 deadline to initiate closure for unlined CCR impoundments and impoundments that fail the aquifer location restriction will remain in place while EPA completes a new rulemaking to reaffirm or establish a new deadline for initiating closure. PNM cannot predict the outcome of the D.C. Circuit’s consideration of these competing motions, and whether or how such a ruling would affect operations at Four Corners.

The CCR 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 and the determination by EPA that CCRs are non-hazardous. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCR regulation, including mine placement of CCRs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows. Based upon the requirements of the final rule, PNM conducted a CCR 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 would seek recovery from its ratepayers of all CCR costs for retail jurisdictional assets that are ultimately incurred. PNM does not expect the rule to have a material impact on operations, financial position, or cash flows.

As indicated above, CCRs at Four Corners are currently disposed of in ash ponds and dry storage areas. The CCR rule requires ongoing, phased groundwater monitoring. Utilities that own or operate CCR disposal units, such as those at Four Corners were required to collect 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 CCR rule’s standards, the rule required the initiation of an assessment monitoring program by April 15, 2018.  If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed. Four Corners completed an analysis that determined several of its CCR disposal units will need corrective action or will need to cease operations and initiate closure by October 2020. Four Corners anticipates it will complete its evaluation of these matters, including gathering additional groundwater data, soliciting public comment, and selecting potential actions, by the summer of 2019. At this time, PNM does not anticipate its share of the cost to complete these corrective actions or to close the CCR disposal units at Four Corners will have a significant impact on its operations, financial position, or cash flows.

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. In addition to coal delivered to meet the current needs of SJGS, PNM has prepaid SJCC for certain coal mined but not yet delivered to the plant site. At March 31, 2019 and December 31, 2018, prepayments for coal, which are included in other current assets, amounted to $26.3 million. Additional information concerning the coal supply for SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

In conjunction with the activities undertaken to comply with the CAA for SJGS, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS. On July 1, 2015, PNM and Westmoreland entered into a new coal supply agreement (the “SJGS CSA”), pursuant to which Westmoreland agreed to supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland agreed to provide CCR 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.

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 CCR disposal and mine reclamation services were assigned to SJCC. As discussed in Note 6, with the closing of the sale of the assets of SJCC on March 15, 2019, WSJ LLC assumed the rights and obligations of SJCC under the SJGS CSA and the agreements for CCR disposal and mine reclamation services. Pricing under the SJGS CSA is primarily fixed, with adjustments to reflect changes in general inflation. The pricing structure takes into account that WSJ LLC has been paid for coal mined but not delivered.

PNM had 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, the SJGS CSA provides that PNM must have given written notice of that intent by July 1, 2018 and the parties must have agreed to the terms of the extension by January 1, 2019. In addition, the SJPPA obligates each SJGS participant to provide notice to the other participants whether they wish to extend the terms of the SJPPA and the SJGS CSA beyond June 30, 2022. In 2018, PNM, Los Alamos, UAMPS, and Tucson provided notice of their intent to exit SJGS in 2022 and Farmington gave notice that it wishes to continue SJGS operations and to extend the terms of both agreements. On November 30, 2018, PNM provided notice to Westmoreland that PNM does not intend to extend the term of the SJGS CSA or to negotiate a new coal supply agreement for SJGS, which will result in the current agreement expiring on its own terms on June 30, 2022. See December 2018 Compliance Filing above.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC was 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. As discussed in Note 6, on March 15, 2019, the assets owned by SJCC were sold to WSJ LLC, a subsidiary of Westmoreland Mining Holdings, LLC. Under the sale agreement, WSJ LLC assumed the rights and obligations of SJCC, including obligations to PNMR under the outstanding letters of credit.

Four Corners

APS purchases all of Four Corners’ coal requirements from NTEC, an entity owned by the Navajo Nation, under a coal supply contract (the “Four Corners CSA”) that expires in 2031. The coal comes from reserves located within the Navajo Nation. NTEC has contracted with Bisti Fuels Company, LLC, a subsidiary of The North American Coal Corporation, for management and operation of the mine. The contract provides for pricing adjustments over its term based on economic indices. See additional discussion of the Four Corners CSA in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Coal Mine Reclamation

As indicated under Coal Combustion Residuals Waste Disposal above, SJGS currently disposes of CCRs in the surface mine pits adjacent to the plant and Four Corners disposes of CCRs in ponds and dry storage areas. As discussed in Note 16 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, in conjunction with the shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA, the SJGS participants requested that the coal mine reclamation study for SJGS be updated periodically. The SJGS RA required PNM to complete an update to the reclamation cost estimate after the December 31, 2017 shutdown of SJGS Units 2 and 3. This reclamation cost estimate was completed in October 2018 and assumed continuation of mining operations through 2053. The 2018 study indicated a decrease in reclamation costs primarily driven by lower inflationary factors used to determine the estimated future cost of reclamation activities. PNM recorded its $2.5 million share of this decrease as of September 30, 2018 as regulatory disallowances and restructuring costs in the Condensed Consolidated Statements of Earnings.

As discussed above, on December 31, 2018, PNM submitted the December 2018 Compliance Filing to the NMPRC indicating that, consistent with the conclusions reached in PNM’s 2017 IRP (Note 12), PNM expects to retire its share of SJGS after the current SJGS CSA expires in mid-2022. PNM determined that recent events and circumstances regarding SJGS, including the December 2018 Compliance Filing, indicate that it is more likely than not that PNM’s share of SJGS will be retired in 2022. As a result, in December 2018 PNM again remeasured its liability for coal mine reclamation for the mine that serves SJGS to reflect that reclamation activities may occur beginning in 2022, rather than in 2053 as previously anticipated. This estimate resulted in an increase in overall reclamation costs due to an increase in the amount of fill dirt required to remediate the mine areas and the timing of activities necessary to reclaim the mine that serves SJGS. This remeasurement increased PNM’s liability for coal mine reclamation as of December 31, 2018 by $39.2 million, which reflects the increase in PNM’s obligation for both the underground and surface mines that serve SJGS. PNM recovers from retail customers reclamation costs associated with the underground mine. However, the NMPRC has capped the amount that can be collected from retail customers for final reclamation of the surface mines at $100.0 million. As a result, PNM recorded $9.4 million of the increase in the liability at December 31, 2018 related to the underground mine in regulatory assets on the Consolidated Balance Sheets and recorded the remaining $29.8 million associated with the surface mine as regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings. PNM’s estimate of the costs necessary to reclaim the mine that serves SJGS is subject to many assumptions, including the timing of reclamation, generally accepted practices at the time reclamation activities occur, and then current inflation and discount rates. In addition, PNM may be exposed to additional loss if the cost of reclamation activities are not approved by the NMPRC in connection with the NMPRC approvals indicated above.

The current estimate for decommissioning the mine serving Four Corners reflects the operation of the mine through 2031, the term of the Four Corners CSA.

Based on the 2018 estimates and PNM’s ownership share of SJGS, PNM’s remaining payments as of March 31, 2019 for mine reclamation, in future dollars, are estimated to be $102.6 million for the surface mines at both SJGS and Four Corners and $40.0 million for the underground mine at SJGS. At March 31, 2019 and December 31, 2018, liabilities, in current dollars, of $70.4 million and $70.1 million for surface mine reclamation and $23.8 million and $23.2 million for underground mine reclamation were recorded in other deferred credits.

Under the terms of the SJGS CSA, PNM and the other SJGS owners are obligated to compensate WSJ LLC 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 WSJ LLC for post-term reclamation obligations. As discussed in Note 16 of the Notes to the Consolidated Financial Statements on Form 10-K, as part of the restructuring of SJGS ownership the SJGS owners negotiated the terms of an amended agreement to fund post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable reclamation trust, and periodically deposit funds into the reclamation trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels. PNM funded $10.0 million in December 2018. Based on PNM’s reclamation trust fund balance at March 31, 2019, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $6.5 million in 2019, $10.2 million in 2020, and $10.9 million in 2021.

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 2018 and anticipates providing additional funding of $2.3 million in each of the years from 2019 through 2021.

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 impacts of changes in New Mexico state law as a result of the enactment of the ETA and regulatory determinations made by the NMPRC may also affect PNM’s financial position, results of operations, and cash flows. 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. 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 $14.1 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 $13.6 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 $41.6 million, with a maximum annual payment limitation of $6.2 million, to be adjusted periodically for inflation.

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.

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 2018 through 2021 has been endorsed by the parties and is being reviewed by the New Mexico Office of the 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 NM 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. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM entered its appearance in the appellate case and supported the settlement agreement in the NM District Court. On April 3, 2018, the New Mexico Court of Appeals issued an order affirming the decision of the NM District Court. Several parties filed motions requesting a rehearing with the New Mexico Court of Appeals seeking clarification of the order, which were denied. The State of New Mexico and various other appellants filed a Writ of Certiorari with the NM Supreme Court. The NM Supreme Court granted the State of New Mexico’s petition and denied the other parties’ requests. The issues regarding the Navajo Nation settlement have been briefed and are awaiting a decision by the NM Supreme Court. Adjudication of non-Indian water rights is ongoing.

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 matters 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 is proceeding in NM 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. Mediation was held on January 23, 2019. Discussions are continuing but the matter remains unresolved. 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.

Navajo Nation Allottee Matters

In September 2012, 43 landowners filed a notice of appeal with the Bureau of Indian Affairs (“BIA”) appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The landowners 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 PNM is a rights-of-way grantee 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.  The allottees 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. The allottees filed a motion to dismiss their appeal with prejudice, which was granted in April 2014. 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. 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, which was denied. The NM District Court stayed the case 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. On April 30, 2018, the US Supreme Court declined to hear PNM’s Petition for Writ of Certiorari. The underlying litigation continues in the NM District Court. The NM District Court has not issued an updated scheduling order in the case due to the unresolved ownership of the fifth allotment. On March 27, 2019, several individual allottees filed a motion for partial summary judgment on the issue of trespass. Briefing is underway. PNM cannot predict the outcome of these matters.

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Regulatory and Rate Matters

3 Months Ended

Mar. 31, 2019

Regulated Operations [Abstract]

Regulatory and Rate Matters

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 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

PNM

New Mexico General Rate Cases

New Mexico 2015 General Rate Case (“NM 2015 Rate Case”)

On August 27, 2015, PNM filed an 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 application was based on a future test year (“FTY”) period beginning October 1, 2015 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 other economic factors. The 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. 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 13). 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 CSA (Note 11).  PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current SJGS CSA, 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 13); 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 when the August 2016 RD was issued), but the customers would not bear any capital or depreciation costs other than those related to improvements made after the date of the original leases

• Disallowing recovery from retail customers of the rent expense, which aggregates $18.1 million per year, under the four leases of capacity in PVNGS Unit 1 that were extended for eight years beginning January 15, 2015 and the one lease of capacity in PVNGS Unit 2 that was extended for eight years beginning January 15, 2016 (Note 13) and related property taxes, which were $1.5 million per year when the August 2016 RD was issued; 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 11); 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. 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 for requiring 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 proposed retail customers receive 100% of the New Mexico jurisdictional portion of revenues from “refined coal” (a third-party pre-treatment process) at SJGS. 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

• Allowing 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

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. In addition, PNM’s statement indicated it is appealing the following specific elements of the NMPRC’s order:

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

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

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

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

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

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

• The NMPRC allowing PNM to recover the costs incurred under the new Four Corners CSA

• 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

The NM Supreme Court orally 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.

GAAP requires a loss 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. As of September 30, 2016, PNM estimated 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. 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 would not be recovered 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.

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 has been recorded related to the issues subject to the cross-appeals.

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. As a result, PNM reevaluated the accounting consequences of the order in the NM 2015 Rate Case resulting in an additional pre-tax loss of $3.1 million, which represented seven months of capital cost recovery that the order disallowed and was not expected to be recovered through July 31, 2018.

During the second half of 2018, PNM updated its evaluation of the estimated time frame it would take for resolution of the matter resulting in additional pre-tax losses of $4.0 million, representing capital cost recovery that the order disallowed and that PNM estimated would not be recovered through April 30, 2019.

Since the NM Supreme Court did not issue a decision on the appeals by March 31, 2019, PNM again reevaluated the accounting consequences of the order in the NM 2015 Rate Case. As of March 31, 2019, PNM estimates the most likely period for the NM Supreme Court to issue a decision in the case and for the NMPRC to take any on any remanded issues is four months. As a result, PNM recorded an additional pre-tax loss of $1.3 million as of March 31, 2019, representing capital cost recovery that the order disallowed and will not be recovered through July 31, 2019. Further losses will be recorded if the currently estimated time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is 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 March 31, 2019, 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 $72.6 million, after considering the losses recorded to date

• 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 $37.6 million, after considering the losses recorded to date

• The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $49.7 million, after considering the losses recorded to date

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 $144.7 million (which amount includes $72.6 million that is the subject of PNM’s appeal discussed above) at March 31, 2019, after considering the losses recorded to date. 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. PNM’s original application used a FTY beginning January 1, 2018 and requested an increase in base non-fuel revenues of $99.2 million based on an ROE of 10.125%. The primary drivers of PNM’s revenue deficiency included implementation of modifications to PNM’s resource portfolio, which were approved by the NMPRC in December 2015 as part of the SJGS regional haze compliance plan, infrastructure investments, including environmental upgrades at Four Corners, declines in forecasted energy sales due to successful energy efficiency programs and other economic factors, and updates to FERC/retail jurisdictional allocations.

After extensive settlement negotiations and public proceedings, the NMPRC issued a Revised Order Partially Adopting Certification of Stipulation dated January 10, 2018 (the “Revised Order”). The key terms of the Revised Order include:

• An increase in base non-fuel revenues totaling $10.3 million, which includes a reduction to reflect the impact of the decrease in the federal corporate income tax rate and updates to PNM’s cost of debt (aggregating an estimated $47.6 million annually)

• A ROE of 9.575%

• Returning to customers over a three-year period the benefit of the reduction in the New Mexico corporate income tax rate (Note 14) to the extent attributable to PNM’s retail operations

• 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 then projected capital improvements during the period July 1, 2016 through December 31, 2018, but allowing recovery of the total $148.1 million of investments with a debt-only return

• An agreement to not implement non-fuel base rate changes, other than changes related to PNM’s rate riders, with an effective date prior to January 1, 2020

• A requirement to consider the prudency of PNM’s decision to continue its participation in Four Corners in a future proceeding

In accordance with the settlement agreement and the NMPRC’s final order, PNM implemented 50% of the approved increase for service rendered beginning February 1, 2018 and implemented the rest of the increase for service rendered beginning January 1, 2019.

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 and recovered. Initial comments were filed in July 2017 and several public workshops have been held. To date, no agreement has been reached. PNM cannot predict the outcome of this proceeding.

Renewable Portfolio Standard

Prior to the enactment of the ETA, the REA established 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. As discussed in Note 11, the ETA was signed into law on March 22, 2019. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also removes diversity requirements and certain customer caps and exemptions relating to the application of the RPS under the REA.

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. The ETA sets a new threshold based on average annual levelized resource cost basis. 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 Riderbelow.

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

• 157 MW of PNM-owned solar-PV facilities, including 50 MW of PNM-owned solar-PV facilities approved by the NMPRC in PNM’s 2018 renewable energy procurement plan and are expected to be placed in commercial operation by the end of 2019

• 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, 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 15 MW

• Solar distributed generation, aggregating 106.8 MW at March 31, 2019, 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

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, and continuation of customer REC purchase programs and other purchases of RECs to ensure annual compliance with the RPS. 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. 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 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, which was denied. Briefing on NMIEC’s appeal of the fuel allocation methodology is complete. On June 20, 2018, NEE filed its Brief in Chief with the NM Supreme Court stating, among other things, that PNM’s process favored ownership of the 50 MW solar facilities compared to PPAs. PNM and the NMPRC each filed Answer Briefs on September 4, 2018 stating there is substantial evidence in the case record to support the NMPRC’s decision and that PNM’s RFP process was reasonable, complied with RPS requirements, and consistent with industry standards. NEE’s Reply Brief was filed on October 15, 2018. On May 6, 2019, the NM Supreme Court heard oral arguments on the issues of the fuel allocation methodology and the reasonableness of the RFP process. PNM cannot predict the outcome of this matter.

On June 1, 2018, PNM filed its 2019 renewable energy procurement plan. The plan meets RPS and diversity requirements for 2019 and 2020 using resources already approved by the NMPRC and did not propose any significant new procurements. PNM projects that the plan will be within the RCT in 2019 and will slightly exceed the current RCT in 2020. Public hearings were held on the case in September and October 2018. The NMPRC approved PNM’s 2019 renewable energy procurement plan on November 28, 2018.

As discussed above, the ETA removes certain customer caps and exemptions relating to the application of the RPS under the REA. As a result of these changes, PNM will be required to procure additional energy from renewable resources to meet the 20% by 2020 requirement under the RPS. PNM expects to request NMPRC approval of a PPA for wind generation capacity, which would utilize the BB2 Line to deliver the power, to meet this requirement. See additional discussion below under Application For a New 345 KV Transmission Line. 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. In its 2019 renewable energy procurement plan case, which was approved by the NMPRC on November 28, 2018, PNM proposed to collect $49.6 million for the year. The 2019 renewable energy procurement plan became effective on January 1, 2019. PNM recorded revenues from the rider of $12.7 million and $10.9 million in the three months ended March 31, 2019 and 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 did not exceed such limitation in 2018.

Energy Efficiency and Load Management

Petition for Energy Efficiency Disincentive

PNM’s application in the NM 2016 Rate Case had requested a “lost contribution to fixed cost” mechanism to address the disincentives associated with PNM’s energy efficiency programs. In the revised stipulation to that case, PNM agreed to withdraw its proposal for such a mechanism and to address energy efficiency disincentives in a future docket. On March 2, 2018, PNM filed a petition proposing a “lost contribution to fixed cost mechanism” with substantially the same terms as those proposed in the NM 2016 Rate Case application. The Hearing Examiner issued a procedural order that included a public hearing to begin on October 30, 2018. Subsequently, the Hearing Examiner extended the deadline to file response testimony until December 19, 2018 and vacated the hearing schedule. On December 19, 2018, the Hearing Examiner approved a joint motion filed by PNM and other parties in the case to hold the proceedings in abeyance until mid-March 2019. During the 2019 New Mexico legislative session, the EUEA was amended to, among other things, include a decoupling mechanism for disincentives, preclude a reduction to a utility’s ROE based on approval of disincentive or incentive mechanisms, and to establish savings targets for the period 2021 through 2025. On May 6, 2019, PNM submitted a request to the NMPRC to dismiss this matter and indicating that PNM will propose a mechanism to address disincentives in accordance with the amended EUEA in a future general rate case filing. PNM cannot predict the outcome of this matter.

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. 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 and because they asserted that the 2014 IRP did not conform to the NMPRC’s IRP rule. 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. On May 4, 2016, the NMPRC issued a 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 the 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 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 Independent System Operator Western Energy Imbalance Market

• PNM should analyze its current Reeves 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. On January 16, 2018, the Hearing Examiner issued an order setting the scope of the proceedings as the 2017 IRP’s compliance with the applicable statute and NMPRC rules. Hearings were held in June 2018. On October 26, 2018, the Hearing Examiner issued a recommended decision recommending that the NMPRC accept PNM’s 2017 IRP as compliant with the applicable statute and NMPRC rules. On December 19, 2018, the NMPRC issued a final order accepting the Hearing Examiner’s recommended decision. On January 18, 2019, the Board of the County of Commissioners for San Juan County, New Mexico, the City of Farmington, New Mexico, and other parties filed a Notice of Appeal with the NM Supreme Court regarding the NMPRC’s final order in PNM’s 2017 IRP. The due date for Statements of Issues in the appeal has been extended to May 10, 2019 at the request of appellants in the case. On January 18, 2019, NEE submitted a motion requesting the NMPRC reconsider its acceptance of PNM’s 2017 IRP and alleging informational inadequacy and deficiencies in PNM’s filing. On January 29, 2019, PNM submitted a filing to the NMPRC in response to NEE’s motion for reconsideration. In its response, PNM stated that the issues raised by NEE had already been considered and rejected by the NMPRC in its December 19, 2018 final order and that the NMPRC lacks jurisdiction over the matters because the NMPRC’s final order has been appealed to the NM Supreme Court. The NMPRC did not take action on NEE’s motion for reconsideration. On February 19, 2019, NEE filed a motion with the NM Supreme Court to intervene in the appeal and to seek remand of the matter to the NMPRC. On March 11, 2019, PNM filed its response with the NM Supreme Court stating that the NMPRC has already considered and, by operation of law, denied NEE’s motion for reconsideration. PNM cannot predict the outcome of this matter.

The NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA required 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. PNM submitted its December 2018 Compliance Filing to the NMPRC on December 31, 2018 indicating that, consistent with the conclusions reached in the 2017 IRP, PNM’s customers would benefit from the retirement of PNM’s share of SJGS in 2022. The December 2018 Compliance Filing and the 2017 IRP are not a final determinations of PNM’s future generation portfolio. Retiring PNM’s share of SJGS capacity will require future NMPRC approval. PNM will also be required to obtain NMPRC approval of an exit from Four Corners, which PNM will seek at an appropriate time in the future. Likewise, NMPRC approval of new generation resources through CCNs, PPAs, or other applicable filings, would be required. The outcome of these future abandonment filings and the related impact on PNM’s generation portfolio will also be significantly influenced by the recent enactment of the ETA. See Note 11. PNM cannot predict the outcome of these matters.

Cost Recovery Related to Joining the EIM

The California Independent System Operator (“CAISO”) developed the Western Energy Imbalance Market (“EIM”) as a real-time wholesale energy trading market that enables participating electric utilities to buy and sell energy. The EIM aggregates the variability of electricity generation and load for multiple balancing authority areas and utility jurisdictions. In addition, the EIM facilitates greater integration of renewable resources through the aggregation of flexible resources by capturing diversity benefits from the expanded geographic footprint and the expanded potential uses for those resources.

In 2018, PNM completed a cost-benefit analysis of participating in the EIM. PNM’s analysis indicated participation in the EIM would provide substantial benefits to retail customers. On August 22, 2018, PNM filed an application with the NMPRC requesting, among other things, to recover an estimated $20.9 million of initial capital investments and authorization to establish a regulatory asset to recover an estimated $7.4 million of other expenses that would be incurred in order to join the EIM. PNM’s application proposed the regulatory asset be adjusted to provide for full recovery of such costs, including carrying charges, until the effective date of new rates in PNM’s next general rate case. PNM’s application also proposed the benefits of participating in the EIM be credited to retail customers through PNM’s existing FPPAC and that PNM would seek recovery of its costs in a future proceeding. A public hearing was held on December 12, 2018. On December 19, 2018, the NMPRC issued an order approving the establishment of a regulatory asset to recover PNM’s cost of joining the EIM. On January 17, 2019, ABCWUA filed a motion to reopen the case and to reconsider the NMPRC’s order approving the establishment of a regulatory asset. PNM submitted its response opposing reconsideration of the case on January 28, 2019. On February 6, 2019, the NMPRC issued an order granting rehearing and vacating the December 19, 2018 order. On February 27, 2019, the NMPRC issued a procedural order appointing a Hearing Examiner and requiring the Hearing Examiner to report to the NMPRC on whether the matter should be reopened. On March 18, 2019, the Hearing Examiner issued a recommended decision recommending approval of the establishment of a regulatory asset but deferring certain rate making issues, including but not limited to issues related to implementation and ongoing EIM costs and savings, the prudence and reasonableness of costs to be included in the regulatory asset, and the period over which costs would be charged to customers. PNM filed limited exceptions to the recommended decision related to the deferral of certain reasonableness findings. The NMPRC issued a final order adopting the Hearing Examiner’s recommended decision on March 27, 2019. On April 12, 2019, PNM and other parties filed a joint motion requesting the NMPRC clarify that the quarterly benefits reports prepared by CAISO be used to determine the benefits of participating in the EIM, as well as to support the prudence of costs incurred to join the EIM. On April 24, 2019, the NMPRC issued an order granting the joint motion for clarification and indicating the CAISO quarterly benefits reports may be used in a future rate case. PNM anticipates it will begin participating in the EIM in April 2021.

Facebook, Inc. Data Center Project

As discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, in 2016, the NMPRC approved a PNM application for arrangements in connection with services to be provided to Facebook, Inc. for a data center being constructed in PNM’s service area. 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. The cost of renewable energy procured is passed through to Facebook under a rate rider. A special service rate is applied to Facebook’s energy consumption in those hours of the month when their consumption exceeds the energy production from the renewable resources. In late 2017, PNM’s executed its initial procurement for the energy production from 30 MW of solar-PV capacity from NMRD, a 50% equity method of investee PNMR Development. Of this capacity, 10 MW began commercial operation in each of January 2018, March 2018, and May 2018.

PNM obtained NMPRC approval to enter into additional 25-year PPAs to purchase renewable energy and RECs to be used by PNM to supply renewable energy to Facebook. These PPAs include the purchase of the power and RECs from:

• Casa Mesa Wind, LLC, a subsidiary of NextEra Energy Resources, LLC, which is located near House, New Mexico, has a total capacity of 50 MW, and became operational in November 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

• Two PPAs to purchase renewable energy and RECs from an aggregate of approximately 100 MW of capacity from two solar-PV facilities to be owned and operated by NMRD. NMRD is required to obtain FERC approval of the PPAs. Subject to FERC approval, the first 50 MW of these facilities is expected to begin commercial operation in December 2019 and the remaining capacity is expected to begin commercial operation in June 2020.

On March 15, 2019, PNM participated with NMRD in an application requesting FERC approval of the two PPAs aggregating approximately 100 MW of capacity. PNM cannot predict if the FERC will approve this filing.

Application For a New 345 KV Transmission Line

On August 10, 2018, PNM filed an application seeking NMPRC approval of a CCN to construct and operate a 345 KV transmission line and associated facilities (the “BB2 Line”), and to determine the rate making treatment to apply to the BB2 line and related rights-of-way. In the application, PNM states that the BB2 line would run adjacent to one of PNM’s existing transmission lines and is necessary to serve additional renewable generating resources to be located in eastern New Mexico. PNM’s use of the BB2 line would benefit all customers and would include delivery of approximately 166 MW of renewable energy and RECs under a PPA, which had previously been approved by the NMPRC, from La Joya Wind. The energy and RECs from the La Joya Wind PPA would be used to a serve the needs of a data center being constructed in PNM’s service territory and the capacity and energy from the PPA will also be used to meet the system needs of all PNM customers. See additional discussion in Facebook, Inc. Data Center Project above. PNM’s application requested that the NMPRC apply standard ratemaking treatment to the estimated $85 million cost of the project resulting in a jurisdictional allocation of costs to all of PNM’s transmission and retail customers. NMPRC staff supported PNM’s proposed ratemaking treatment of the BB2 project and indicated that the capacity and energy of the La Joya PPA and related network upgrades to PNM’s transmission system would benefit all of PNM’s customers. On March 11, 2019, the Hearing Examiner assigned to the application issued a recommended decision recommending approval of the CCN and related rights-of-way but recommending the NMPRC deny PNM’s request to allocate a portion of cost of the BB2 Line to retail customers. The Hearing Examiner’s recommendation indicated the costs not recovered from retail customers be directly reimbursed to PNM by Facebook, Inc. As a result, Facebook, Inc. would be responsible for approximately 46 percent, or $39.0 million, of the estimated cost of the project. On March 20, 2019, PNM filed exceptions to the recommended decision and requested oral argument. In its filing, PNM refuted the proposed finding that the BB2 Line is not part of PNM’s overall transmission system, opposed the recommendation that approximately 46 percent of the estimated cost of the project be directly assigned to Facebook, Inc. and presented legal arguments in support of PNM’s originally proposed ratemaking treatment. On April 16, 2019, the NMPRC issued an order approving the Hearing Examiner’s recommended decision, including the requirement that PNM be directly reimbursed by Facebook, Inc. In late April 2019, PNM and other parties submitted filings with the NMPRC requesting rehearing and seeking reconsideration of the NMPRC’s decision to deny standard ratemaking treatment of the cost of the BB2 Line and associated facilities. PNM cannot predict the outcome of this matter.

TNMP

TNMP 2018 Rate Case

On May 30, 2018, TNMP filed a general rate proceeding with the PUCT (the “TNMP 2018 Rate Case”) requesting an annual increase to base rates of $25.9 million based on a requested ROE of 10.5%, a cost of debt of 7.2%, and a capital structure comprised of 50% debt and 50% equity. TNMP’s application included a request to establish new rate riders to recover Hurricane Harvey restoration, rate case, and additional vegetation management costs. The application also included the integration of revenues previously recorded under the AMS rider and collection of other unrecovered AMS investments into base rates. In 2018, TNMP recorded revenues of $20.2 million under the AMS rider. The TNMP 2018 Rate Case application also proposed to return the regulatory liability recorded at December 31, 2017 related to federal tax reform to customers and to reduce the federal corporate income tax rate to 21%.

On December 20, 2018, the PUCT approved an unopposed settlement agreement in the case. The PUCT’s final order results in a $10.0 million annual increase to base rates. The key elements of the approved settlement include a ROE of 9.65%, a cost of debt of 6.44%, and a capital structure comprised of 55% debt and 45% equity. As stated by the settlement agreement, the PUCT’s final order excludes certain items from rate base that were requested in TNMP’s original filing, including approximately $10.6 million of transmission investments that TNMP included in its January 2019 transmission cost of service filing, which was approved by the PUCT in March 2019. In addition, the PUCT’s final order requires TNMP to refund approximately $37.8 million of the regulatory liability recorded at December 31, 2017 related to federal tax reform to customers over a period of five years and the remaining amount over the estimated useful lives of plant in service as of December 31, 2017; approves TNMP’s request to integrate revenues historically recorded under TNMP’s AMS rider, as well as other unrecovered AMS investments, into base rates; approves TNMP’s request for new depreciation rates; and approves a new rider to recover Hurricane Harvey restoration costs, net of amounts to be refunded to customers resulting from the reduction in the federal income tax rate in 2018. See Note 14. The TNMP 2018 Rate Case also resulted in a reallocation of costs between TNMP’s transmission and retail customers and other rate design changes that reallocated costs between certain demand-based customers and customers billed on a volumetric basis. New rates under the TNMP 2018 Rate Case were effective beginning January 1, 2019.

Transmission Cost of Service Rates

TNMP can update its transmission cost of service (“TCOS”) rates twice per year to reflect changes in its invested capital although updates are not allowed while a general rate case is in process. 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)
September 8, 2016	$	9.5	$	1.8
March 14, 2017	30.2		4.8
September 13, 2017	27.5		4.7
March 27, 2018	32.0		0.6
March 21, 2019	111.8		14.3

Order Related to Changes in Federal Income Tax Rates

On January 25, 2018, the PUCT issued an accounting order that addresses the change in the federal corporate income tax rates on investor-owned utilities in the state of Texas. The order required 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 corporate income tax rate.

In addition, the order required 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 (Note 14). In compliance with the PUCT order, during the three months ended March 31, 2018, TNMP reduced revenues by $1.5 million to reflect the impact of the reduction in the federal corporate income tax rate beginning January 25, 2018. As discussed above, the total amount owed for the year ended 2018 of $5.4 million was offset against TNMP’s Hurricane Harvey restoration costs as of December 31, 2018 and is being refunded to customers as a component of a new rate rider over a period of no more than five years beginning on January 1, 2019.

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 and over collected costs from prior years, rate case expenses, and performance bonuses (if programs exceed mandated savings goals). On May 30, 2018, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2019. The total amount requested was $5.7 million, which included a performance bonus of $0.9 million based on TNMP’s energy efficiency achievements in the 2017 plan year. On June 21, 2018, the PUCT issued a declaratory order announcing the PUCT’s interpretation of the bonus calculation in its rule. The order does not affect cost recovery but reduces the bonus calculation as filed by utilities in their current EECRF proceedings. Accordingly, in June of 2018, TNMP reduced its estimated performance bonus for the 2017 plan year to $0.8 million. On August 6, 2018, TNMP and other parties to the case reached a unanimous settlement stipulation to provide $5.6 million of EECRF recovery, which includes a performance bonus of $0.8 million. On October 12, 2018, the PUCT approved the settlement stipulation with rates to become effective on March 1, 2019.

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Lease Commitments

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Lease Commitments

Lease Commitments

The Company enters into various lease agreements to meet its business needs and to satisfy the needs of its customers. Historically, the Company’s leases were classified as operating leases which included leases for generating capacity from PVNGS Units 1 and 2, certain rights-of-way agreements for transmission lines and facilities, vehicle and equipment leases necessary to construct and maintain the Company’s assets and building and office equipment leases. In February 2016, the FASB issued ASU 2016-02 - Leases (Topic 842) to provide guidance on the recognition, measurement, presentation, and disclosure of leases. Among other things, ASU 2016-02 requires that all leases be recorded on the balance sheets by recognizing a present value liability for future cash flows of the lease agreement and a corresponding right-of-use asset. The Company adopted Topic 842 on January 1, 2019, its required effective date. The Company elected to use many of the practical expedients available upon adoption of the standard. As a result, the Company will continue to classify its leases existing as of December 31, 2018 as operating leases until they expire or are modified. In addition, the Company elected the practical expedient to not reevaluate the accounting for land easements and rights-of-way agreements existing at December 31, 2018. The Company also elected the use of the practical expedient to apply the requirements of the new standard on its effective date and has not restated prior periods to conform to the new guidance. Adoption of the lease standard has a material impact on the Company’s Condensed Consolidated Balance Sheets but does not have a material impact on the Condensed Consolidated Statements of Earnings or the Condensed Consolidated Statements of Cash Flows.

Effective January 1, 2019, the Company accounts for contracts that convey the use and control of identified assets for a period of time as leases. The Company classifies leases as operating or financing by evaluating the terms of the lease agreement. Agreements under which the Company is likely to utilize substantially all of the economic value or life of the asset or which the Company is likely to own at the end of the lease term, either through purchase or transfer of ownership, are classified as financing leases. Leases not meeting these criteria are accounted for as operating leases. Agreements under which the Company is a lessor are insignificant. Leases with terms that are expected to exceed one year are recognized on the Company’s Condensed Consolidated Balance sheet by recording a lease liability and corresponding right-of-use asset. PNMR, PNM, and TNMP determine present value for their leases using their incremental borrowing rates at the commencement date of the lease or, when readily available, the rate implicit in the agreement. However, in most cases the implicit interest rate is not available in the Company’s lease agreements. Operating lease expense is recognized within operating expenses according to the use of the asset on a straight-line basis. Financing lease costs are recognized by amortizing the right-of-use asset on a straight-line basis and by recording interest expense on the lease liability. Financing lease right-of-use assets amortization is reflected in depreciation and amortization and interest on financing lease liabilities is reflected as interest charges on the Company’s Condensed Consolidated Statements of Earnings.

PVNGS

PNM leases interests in Units 1 and 2 of PVNGS. 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. Following procedures set forth in the PVNGS leases, PNM notified four of the lessors under the Unit 1 leases and one lessor under the Unit 2 lease that it would elect to renew those leases on the expiration date of the original leases. 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 lease payments during the renewal periods aggregate $16.5 million for PVNGS Unit 1 and $1.6 million for Unit 2.

The terms of each of the extended leases do not provide for additional renewal options beyond their currently scheduled expiration dates. PNM has the option to purchase the assets underlying each of the extended leases at their fair market value or to return the lease interests to the lessors on the expiration dates. Under the terms of the extended leases, PNM has until January 15, 2020 for the Unit 1 leases and January 15, 2021 for the Unit 2 lease to provide notices to the lessors of PNM’s intent to exercise the purchase options or to return the leased assets to the lessors. PNM’s elections are independent for each lease and are irrevocable. In the proceeding addressing PNM’s 2017 IRP (Note 12), PNM agreed to promptly notify the NMPRC of a decision to extend the Unit 1 or 2 leases, or to exercise its option to purchase the leased assets at fair market value upon the expiration of leases. If PNM elects to exercise its purchase option under any of the leases, the leases provide an appraisal process to determine fair market value. If PNM elects to return the assets underlying the extended leases, PNM will retain certain obligations related to PNVGS, including costs to decommission the facility. PNM would seek to recover its undepreciated investments at the end of the PVNGS leases as well as any future obligations related to PNM’s leased capacity from NM retail customers. Any transfer of the assets underlying the leases will be required to comply with NRC licensing requirements.

On April 22, 2019, NEE and other parties, which consist primarily of environmental not-for-profit organizations, filed a joint petition for expedited investigation with the NMPRC. The joint petition requests the NMPRC open an investigation regarding PNM’s option to purchase the assets underlying the PVNGS Unit 1 and 2 leases that will expire in January 2023 and 2024. PNM cannot predict the outcome of this matter.

PNM elected to purchase the assets underlying the other three PVNGS Unit 2 leases at the end of their original lease terms. PNM and the lessors under those leases entered into agreements that established the purchase price, representing the fair market value, to be paid by PNM. 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 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case, including PNM’s pending appeal to the NM Supreme Court of certain matters in the 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 lessors, and take title to the leased interests. If such an event had occurred as of March 31, 2019, amounts due to the lessors under the circumstances described above would be up to $161.2 million, payable on July 15, 2019 in addition to the scheduled lease payments due on July 15, 2019. In such event, PNM would record the acquired assets at the lower of their fair value or the amount paid.

Land Easements and Rights-of-Ways

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. 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. PNM’s April 2018 payment for the amount due under the Navajo Nation right-of-way lease was $6.9 million, which included amounts due under the Consumer Price Index adjustment, and was used to determine PNM’s operating lease liability as of January 1, 2019 and is included in the table of future lease payments shown below. Changes in the Consumer Price Index subsequent to January 1, 2019 are considered variable lease payments.

Fleet Vehicles and Equipment

As of December 31, 2018, all of the Company’s leases of fleet vehicles and equipment are classified as operating leases. Historically, the Company has utilized substantially all of the economic value of its fleet and equipment leases by the end of the lease term. The Company generally has the contractual ability to return its fleet vehicle and equipment leases to the lessor after one-year provided the lessor can recover remaining amounts owed under the agreement from third-parties or through make-whole provisions in the contract but does not typically exercise this right. As a result, fleet vehicle and equipment leases commencing on or after January 1, 2019 are classified as financing leases. The Company’s fleet vehicle and equipment lease agreements include non-lease components for insignificant administrative and other costs that are billed over the life of the agreement. The Company has elected to combine these fees with the lease components of the agreement. Certain of the Company’s fleet vehicle and equipment leases contain residual value guarantees. At March 31, 2019, residual value guarantees on fleet vehicle and equipment leases are $0.5 million, $1.1 million, and $1.6 million for PNM, TNMP, and PNMR.

Other

The Company holds a number of office space and office equipment leases. The Company’s current office space leases, all of which existed as of December 31, 2018, are classified as operating leases. These agreements include non-lease components for costs such as common area maintenance fees, which the Company has elected to combine with the lease component of the agreements. Certain of the Company’s office space leases are held between the Company’s consolidated subsidiaries and have been eliminated on consolidation. See Note 15. The Company’s office equipment leases are primarily for copiers and other graphics equipment. The Company classifies its office equipment leases existing as of December 31, 2018 as operating leases. Office equipment leases commencing on or after January 1, 2019 are classified as financing leases.

Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below:

	March 31, 2019						January 1, 2019
	PNM		TNMP		PNMR Consolidated		PNM		TNMP		PNMR Consolidated
	(In thousands)
Operating leases:
Operating lease assets, net of amortization	$	137,756	$	12,160	$	150,426	$	143,816	$	12,942	$	157,440
Current portion of operating lease liabilities	22,762		3,023		26,197		21,589		3,132		25,189
Long-term portion of operating lease liabilities	115,436		9,088		124,937		124,891		9,787		135,174

As discussed above, the Company classifies its fleet vehicle and equipment leases and its office equipment leases commencing on or after January 1, 2019 as financing leases. Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below:

	March 31, 2019
	PNM			TNMP			PNMR Consolidated
	(In thousands)
Financing leases:
Non-utility property	$	1,635		$	1,268		$	2,904
Accumulated depreciation	(37		)	(40		)	(78		)
Non-utility property, net	$	1,598		$	1,228		$	2,826
Other current liabilities	$	233		$	217		$	450
Other deferred credits	1,083			1,006			2,089

Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below:

	March 31, 2019
	PNM		TNMP		PNMR Consolidated
Weighted average remaining lease term (In years):
Operating leases	7.18		4.67		6.95
Financing leases	5.72		5.75		5.74
Weighted average discount rate:
Operating leases	3.88	%	3.88	%	3.88	%
Financing leases	4.34	%	4.55	%	4.43	%

Information for the components of lease expense is as follows:

	Three Months Ended March 31, 2019
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Total operating lease expense	$	7,231	$	241	$	7,611
Financing lease expense:
Amortization of right-of-use assets	66		58		125
Interest on lease liabilities	16		17		32
Total financing lease expense	82		75		157
Variable lease expense	—		—		—
Short-term lease expense	74		3		94
Total lease expense for the period	$	7,387	$	319	$	7,862

Supplemental cash flow information related to the Company’s leases is as follows:

	Three Months Ending March 31, 2019
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	9,452	$	284	$	9,891
Operating cash flows from financing leases	16		17		32
Finance cash flows from financing leases	25		33		58
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	143,816	$	12,942	$	157,440
Financing leases	1,635		1,268		2,904

Excluded from the lease expense and cash flow information tables above are $0.4 million, $0.7 million, and $1.1 million of capitalized operating lease costs, and less than $0.1 million of capitalized financing lease costs at PNM, TNMP, and PNMR. These capitalized costs are reflected as investing activities on the Company’s Condensed Consolidated Statements of Cash Flows.

Future expected lease payments as of March 31, 2019 and December 31, 2018 are shown below:

	As of March 31, 2019
	PNM				TNMP				PNMR Consolidated
	Financing		Operating		Financing		Operating		Financing		Operating
	(In thousands)
Remainder of 2019	$	266	$	17,917	$	209	$	2,622	$	475	$	20,980
2020	344		27,045		269		2,993		613		30,555
2021	332		26,505		259		2,398		591		29,158
2022	319		26,235		249		1,846		568		28,255
2023	307		17,457		181		1,281		488		18,879
Later years	224		42,328		214		1,151		438		43,490
Total minimum lease payments	1,792		157,487		1,381		12,291		3,173		171,317
Less: Imputed interest	476		19,289		158		180		634		20,183
Lease liabilities as of March 31, 2019	$	1,316	$	138,198	$	1,223	$	12,111	$	2,539	$	151,134

	As of December 31, 2018
	Operating leases
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Remainder of 2019	$	27,691	$	3,664	$	31,772
2020	27,000		3,102		30,404
2021	26,462		2,324		29,012
2022	26,217		1,795		28,175
2023	17,447		1,279		18,868
Later years	42,329		1,150		43,489
Total minimum lease payments	167,146		13,314		181,720

The above tables include $9.9 million, $12.2 million, and $22.1 million for PNM, TNMP, and PNMR at March 31, 2019 and $7.5 million, $11.0 million, and $18.5 million for PNM, TNMP, and PNMR at December 31, 2018 for expected future payments on fleet vehicle and equipment leases that could be avoided if the leases were returned and the lessor is able to recover estimated market value for the equipment from third parties. The Company’s contractual commitments for leases that have not yet commenced are insignificant.

Lease Commitments

Lease Commitments

The Company enters into various lease agreements to meet its business needs and to satisfy the needs of its customers. Historically, the Company’s leases were classified as operating leases which included leases for generating capacity from PVNGS Units 1 and 2, certain rights-of-way agreements for transmission lines and facilities, vehicle and equipment leases necessary to construct and maintain the Company’s assets and building and office equipment leases. In February 2016, the FASB issued ASU 2016-02 - Leases (Topic 842) to provide guidance on the recognition, measurement, presentation, and disclosure of leases. Among other things, ASU 2016-02 requires that all leases be recorded on the balance sheets by recognizing a present value liability for future cash flows of the lease agreement and a corresponding right-of-use asset. The Company adopted Topic 842 on January 1, 2019, its required effective date. The Company elected to use many of the practical expedients available upon adoption of the standard. As a result, the Company will continue to classify its leases existing as of December 31, 2018 as operating leases until they expire or are modified. In addition, the Company elected the practical expedient to not reevaluate the accounting for land easements and rights-of-way agreements existing at December 31, 2018. The Company also elected the use of the practical expedient to apply the requirements of the new standard on its effective date and has not restated prior periods to conform to the new guidance. Adoption of the lease standard has a material impact on the Company’s Condensed Consolidated Balance Sheets but does not have a material impact on the Condensed Consolidated Statements of Earnings or the Condensed Consolidated Statements of Cash Flows.

Effective January 1, 2019, the Company accounts for contracts that convey the use and control of identified assets for a period of time as leases. The Company classifies leases as operating or financing by evaluating the terms of the lease agreement. Agreements under which the Company is likely to utilize substantially all of the economic value or life of the asset or which the Company is likely to own at the end of the lease term, either through purchase or transfer of ownership, are classified as financing leases. Leases not meeting these criteria are accounted for as operating leases. Agreements under which the Company is a lessor are insignificant. Leases with terms that are expected to exceed one year are recognized on the Company’s Condensed Consolidated Balance sheet by recording a lease liability and corresponding right-of-use asset. PNMR, PNM, and TNMP determine present value for their leases using their incremental borrowing rates at the commencement date of the lease or, when readily available, the rate implicit in the agreement. However, in most cases the implicit interest rate is not available in the Company’s lease agreements. Operating lease expense is recognized within operating expenses according to the use of the asset on a straight-line basis. Financing lease costs are recognized by amortizing the right-of-use asset on a straight-line basis and by recording interest expense on the lease liability. Financing lease right-of-use assets amortization is reflected in depreciation and amortization and interest on financing lease liabilities is reflected as interest charges on the Company’s Condensed Consolidated Statements of Earnings.

PVNGS

PNM leases interests in Units 1 and 2 of PVNGS. 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. Following procedures set forth in the PVNGS leases, PNM notified four of the lessors under the Unit 1 leases and one lessor under the Unit 2 lease that it would elect to renew those leases on the expiration date of the original leases. 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 lease payments during the renewal periods aggregate $16.5 million for PVNGS Unit 1 and $1.6 million for Unit 2.

The terms of each of the extended leases do not provide for additional renewal options beyond their currently scheduled expiration dates. PNM has the option to purchase the assets underlying each of the extended leases at their fair market value or to return the lease interests to the lessors on the expiration dates. Under the terms of the extended leases, PNM has until January 15, 2020 for the Unit 1 leases and January 15, 2021 for the Unit 2 lease to provide notices to the lessors of PNM’s intent to exercise the purchase options or to return the leased assets to the lessors. PNM’s elections are independent for each lease and are irrevocable. In the proceeding addressing PNM’s 2017 IRP (Note 12), PNM agreed to promptly notify the NMPRC of a decision to extend the Unit 1 or 2 leases, or to exercise its option to purchase the leased assets at fair market value upon the expiration of leases. If PNM elects to exercise its purchase option under any of the leases, the leases provide an appraisal process to determine fair market value. If PNM elects to return the assets underlying the extended leases, PNM will retain certain obligations related to PNVGS, including costs to decommission the facility. PNM would seek to recover its undepreciated investments at the end of the PVNGS leases as well as any future obligations related to PNM’s leased capacity from NM retail customers. Any transfer of the assets underlying the leases will be required to comply with NRC licensing requirements.

On April 22, 2019, NEE and other parties, which consist primarily of environmental not-for-profit organizations, filed a joint petition for expedited investigation with the NMPRC. The joint petition requests the NMPRC open an investigation regarding PNM’s option to purchase the assets underlying the PVNGS Unit 1 and 2 leases that will expire in January 2023 and 2024. PNM cannot predict the outcome of this matter.

PNM elected to purchase the assets underlying the other three PVNGS Unit 2 leases at the end of their original lease terms. PNM and the lessors under those leases entered into agreements that established the purchase price, representing the fair market value, to be paid by PNM. 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 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case, including PNM’s pending appeal to the NM Supreme Court of certain matters in the 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 lessors, and take title to the leased interests. If such an event had occurred as of March 31, 2019, amounts due to the lessors under the circumstances described above would be up to $161.2 million, payable on July 15, 2019 in addition to the scheduled lease payments due on July 15, 2019. In such event, PNM would record the acquired assets at the lower of their fair value or the amount paid.

Land Easements and Rights-of-Ways

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. 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. PNM’s April 2018 payment for the amount due under the Navajo Nation right-of-way lease was $6.9 million, which included amounts due under the Consumer Price Index adjustment, and was used to determine PNM’s operating lease liability as of January 1, 2019 and is included in the table of future lease payments shown below. Changes in the Consumer Price Index subsequent to January 1, 2019 are considered variable lease payments.

Fleet Vehicles and Equipment

As of December 31, 2018, all of the Company’s leases of fleet vehicles and equipment are classified as operating leases. Historically, the Company has utilized substantially all of the economic value of its fleet and equipment leases by the end of the lease term. The Company generally has the contractual ability to return its fleet vehicle and equipment leases to the lessor after one-year provided the lessor can recover remaining amounts owed under the agreement from third-parties or through make-whole provisions in the contract but does not typically exercise this right. As a result, fleet vehicle and equipment leases commencing on or after January 1, 2019 are classified as financing leases. The Company’s fleet vehicle and equipment lease agreements include non-lease components for insignificant administrative and other costs that are billed over the life of the agreement. The Company has elected to combine these fees with the lease components of the agreement. Certain of the Company’s fleet vehicle and equipment leases contain residual value guarantees. At March 31, 2019, residual value guarantees on fleet vehicle and equipment leases are $0.5 million, $1.1 million, and $1.6 million for PNM, TNMP, and PNMR.

Other

The Company holds a number of office space and office equipment leases. The Company’s current office space leases, all of which existed as of December 31, 2018, are classified as operating leases. These agreements include non-lease components for costs such as common area maintenance fees, which the Company has elected to combine with the lease component of the agreements. Certain of the Company’s office space leases are held between the Company’s consolidated subsidiaries and have been eliminated on consolidation. See Note 15. The Company’s office equipment leases are primarily for copiers and other graphics equipment. The Company classifies its office equipment leases existing as of December 31, 2018 as operating leases. Office equipment leases commencing on or after January 1, 2019 are classified as financing leases.

Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below:

	March 31, 2019						January 1, 2019
	PNM		TNMP		PNMR Consolidated		PNM		TNMP		PNMR Consolidated
	(In thousands)
Operating leases:
Operating lease assets, net of amortization	$	137,756	$	12,160	$	150,426	$	143,816	$	12,942	$	157,440
Current portion of operating lease liabilities	22,762		3,023		26,197		21,589		3,132		25,189
Long-term portion of operating lease liabilities	115,436		9,088		124,937		124,891		9,787		135,174

As discussed above, the Company classifies its fleet vehicle and equipment leases and its office equipment leases commencing on or after January 1, 2019 as financing leases. Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below:

	March 31, 2019
	PNM			TNMP			PNMR Consolidated
	(In thousands)
Financing leases:
Non-utility property	$	1,635		$	1,268		$	2,904
Accumulated depreciation	(37		)	(40		)	(78		)
Non-utility property, net	$	1,598		$	1,228		$	2,826
Other current liabilities	$	233		$	217		$	450
Other deferred credits	1,083			1,006			2,089

Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below:

	March 31, 2019
	PNM		TNMP		PNMR Consolidated
Weighted average remaining lease term (In years):
Operating leases	7.18		4.67		6.95
Financing leases	5.72		5.75		5.74
Weighted average discount rate:
Operating leases	3.88	%	3.88	%	3.88	%
Financing leases	4.34	%	4.55	%	4.43	%

Information for the components of lease expense is as follows:

	Three Months Ended March 31, 2019
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Total operating lease expense	$	7,231	$	241	$	7,611
Financing lease expense:
Amortization of right-of-use assets	66		58		125
Interest on lease liabilities	16		17		32
Total financing lease expense	82		75		157
Variable lease expense	—		—		—
Short-term lease expense	74		3		94
Total lease expense for the period	$	7,387	$	319	$	7,862

Supplemental cash flow information related to the Company’s leases is as follows:

	Three Months Ending March 31, 2019
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	9,452	$	284	$	9,891
Operating cash flows from financing leases	16		17		32
Finance cash flows from financing leases	25		33		58
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	143,816	$	12,942	$	157,440
Financing leases	1,635		1,268		2,904

Excluded from the lease expense and cash flow information tables above are $0.4 million, $0.7 million, and $1.1 million of capitalized operating lease costs, and less than $0.1 million of capitalized financing lease costs at PNM, TNMP, and PNMR. These capitalized costs are reflected as investing activities on the Company’s Condensed Consolidated Statements of Cash Flows.

Future expected lease payments as of March 31, 2019 and December 31, 2018 are shown below:

	As of March 31, 2019
	PNM				TNMP				PNMR Consolidated
	Financing		Operating		Financing		Operating		Financing		Operating
	(In thousands)
Remainder of 2019	$	266	$	17,917	$	209	$	2,622	$	475	$	20,980
2020	344		27,045		269		2,993		613		30,555
2021	332		26,505		259		2,398		591		29,158
2022	319		26,235		249		1,846		568		28,255
2023	307		17,457		181		1,281		488		18,879
Later years	224		42,328		214		1,151		438		43,490
Total minimum lease payments	1,792		157,487		1,381		12,291		3,173		171,317
Less: Imputed interest	476		19,289		158		180		634		20,183
Lease liabilities as of March 31, 2019	$	1,316	$	138,198	$	1,223	$	12,111	$	2,539	$	151,134

	As of December 31, 2018
	Operating leases
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Remainder of 2019	$	27,691	$	3,664	$	31,772
2020	27,000		3,102		30,404
2021	26,462		2,324		29,012
2022	26,217		1,795		28,175
2023	17,447		1,279		18,868
Later years	42,329		1,150		43,489
Total minimum lease payments	167,146		13,314		181,720

The above tables include $9.9 million, $12.2 million, and $22.1 million for PNM, TNMP, and PNMR at March 31, 2019 and $7.5 million, $11.0 million, and $18.5 million for PNM, TNMP, and PNMR at December 31, 2018 for expected future payments on fleet vehicle and equipment leases that could be avoided if the leases were returned and the lessor is able to recover estimated market value for the equipment from third parties. The Company’s contractual commitments for leases that have not yet commenced are insignificant.

XML

Income Taxes

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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 made 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 eliminated federal bonus depreciation for utilities, limited interest deductibility for non-utility businesses and limited the deductibility of officer compensation. During 2018, the IRS issued additional guidance related to certain officer compensation, as well as proposed regulations on interest deductibility that provide a 10% “de minimis” exception that allows entities with predominantly regulated activities to fully deduct interest expenses. In addition, the IRS issued proposed regulations interpreting Tax Act amendments to depreciation provisions of the Internal Revenue Code that allow the Company to claim a bonus depreciation deduction on certain construction projects placed in service subsequent to the third quarter of 2017. See additional discussion of the impacts of the Tax Act in Note 18 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Beginning February 2018, PNM’s NM 2016 Rate Case reflects the reduction in the federal corporate income rate, including amortization of excess deferred federal income taxes that are being returned to customers over a twenty-one year period; and reductions in the New Mexico corporate tax rate, including amortization of excess deferred state income taxes that are being returned to customers over a three-year period. On January 25, 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. During the three months ended March 31, 2018, TNMP reduced revenue and recorded a regulatory liability of $1.5 million in accordance with the PUCT’s order. The approved settlement in the TNMP 2018 Rate Case includes a reduction in customer rates to reflect the impacts of the Tax Act beginning on January 1, 2019. See additional discussion of PNM’s NM 2016 Rate Case and TNMP’s 2018 Rate Case in Note 12.

As required under GAAP, 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 income taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, including excess tax benefits related to stock awards, be excluded from the estimated annual effective tax rate calculation. At March 31, 2019, PNMR, PNM, and TNMP estimated their effective income tax rates for the year ended December 31, 2019 would be 9.42%, 11.89%, and 8.41%. The primary permanent difference is the reduction in income tax expense resulting from the amortization of excess deferred federal and state income taxes ordered by the NMPRC in PNM’s NM 2016 Rate Case and the amortization of excess deferred federal income taxes as ordered by the PUCT in TNMP’s 2018 Rate Case. During the three months ended March 31, 2019, income tax expense calculated by applying the expected annual effective income tax rate to earnings before income taxes was further reduced by excess tax benefits related to stock awards of $0.7 million for PNMR, of which $0.5 million was allocated to PNM and $0.2 million was allocated to TNMP.

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Related Party Transactions

3 Months Ended

Mar. 31, 2019

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

PNMR, PNM, TNMP, and NMRD 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. In addition, PNMR provides construction and operations and maintenance services to NMRD, a 50% owned subsidiary of PNMR Development (Note 1), and PNM purchases renewable energy from certain NMRD-owned facilities at a fixed price per MWh of energy produced. PNM also provides interconnection services to PNMR Development (Note 9) and NMRD.

The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD:

	Three Months Ended
	March 31,
	2019		2018
	(In thousands)
Services billings:
PNMR to PNM	$	26,826	$	23,679
PNMR to TNMP	10,058		8,365
PNM to TNMP	75		86
TNMP to PNMR	35		35
PNMR to NMRD	41		78
Renewable energy purchases:
PNM from NMRD	625		370
Interconnection billings:
PNM to NMRD	—		—
PNM to PNMR	—		—
Interest billings:
PNMR to PNM	933		62
PNM to PNMR	72		66
PNMR to TNMP	32		8
Income tax sharing payments:
PNMR to PNM	—		—
TNMP to PNMR	—		—

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Significant Accounting Policies and Responsibility for Financial Statements (Policies)

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Principles of Consolidation

The Condensed 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 6). 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’ expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, equity transactions, and interconnection billings (Note 15). All intercompany transactions and balances have been eliminated.

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.

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 certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. In November 2018, the FASB clarified that receivables arising from operating leases are not within the scope of Topic 326 for assets measured at amortized costs. Instead, impairments of receivables arising from operating leases should be accounted for in accordance with Topic 842. The Company anticipates adopting ASU 2016-13 as of January 1, 2020, its required effective date. The Company is in the process of analyzing the impacts of this new standard, but does not anticipate it will have a significant impact on its financial statements.

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, 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 2018-13 – Fair Value Measurements (Topic 820) Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurements

In August 2018, the FASB issued ASU 2018-13 to improve fair value disclosures. ASU 2018-13 eliminates certain disclosure requirements related to transfers between Levels 1 and 2 of the fair value hierarchy and the requirement to disclose the valuation process for Level 3 fair value measurements. ASU 2018-13 also amends certain disclosure requirements for investments measured at net asset value and requires new disclosures for Level 3 investments, including a new requirement to disclose changes in unrealized gains or losses recorded in OCI related to Level 3 fair value measurements. ASU 2018-13 is effective for the Company beginning on January 1, 2020, and permits entities to adopt all or certain elements of the new guidance prior to its effective date. ASU 2018-13 requires retrospective application, except for the new disclosures related to Level 3 investments which are to be applied prospectively. As discussed in Note 9 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 7, PNM and TNMP have investment securities in trusts for decommissioning, reclamation, pension benefits, and other postretirement benefits, which are measured at fair value. Certain investments in these trusts are measured at net asset value per share. These trusts also hold Level 3 investments. The Company is evaluating the requirements of ASU 2018-13, but does not anticipate it will have a significant impact on the Company’s fair value disclosures.

Accounting Standards Update 2018-14 – Compensation - Retirement Benefits - Defined Benefit Plans (Topic 715) Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans

In August 2018, the FASB issued ASU 2018-14 to improve benefit plan sponsors’ disclosures for defined benefit pension and other post-employment benefit plans. ASU 2018-14 removes the requirement to disclose the amounts in other comprehensive income expected to be recognized as benefit cost over the next fiscal year and the requirement to disclose the impact of a one-percentage-point change in the assumed health care cost trend rate; clarifies the disclosure requirements for plans with assets that are less than their projected benefit, or accumulated benefit obligation; and requires significant gains and losses affecting benefit obligations during the period be disclosed. ASU 2018-14 is effective for the Company on December 31, 2020, although early adoption is permitted, and requires retrospective application. As discussed in Note 11 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 10, PNM and TNMP maintain qualified defined benefit, other postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The Company is evaluating the requirements of ASU 2018-14 but does not anticipate these changes will have a significant impact on the Company’s defined benefit and other postretirement benefit plan disclosures.

Accounting Standards Update 2018-15 – Intangibles - Goodwill and Other - Internal Use Software (Topic 350): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract

In August 2018, the FASB issued ASU 2018-15 to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for implementation costs incurred to develop or obtain internal-use software. Under ASU 2018-15, entities are required to capitalize implementation costs for hosting arrangements if those costs meet the capitalization requirements for internal-use software arrangements. ASU 2018-15 requires entities to present cash flows, capitalized costs, and amortization expense in the same financial statement line items as other costs incurred for such hosting arrangements. ASU 2018-15 is effective for the Company on January 1, 2020, although early adoption is permitted, and allows entities to apply the new requirements retrospectively or prospectively. The Company is in the process of analyzing the impacts of this new standard.

Accounting Standards Update 2018-18 - Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606

In November 2018, the FASB issued ASU 2018-18 to clarify transactions between collaborative arrangement participants that should be recognized as revenue under Topic 606. ASU 2018-18 is effective for the Company on January 1, 2020, although early adoption is permitted, and requires retrospective application. The Company has collaborative arrangements related to its interests in SJGS, Four Corners, PVNGS, and Luna. The Company believes its current accounting practices comply with the requirements of ASU 2018-18 but is in the process of analyzing the impacts of the new standard.

GAAP requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as operating cash flows when used to reduce income taxes payable.

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.

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2019

Segment Reporting [Abstract]

Summary of Financial Information by Segment

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

PNMR SEGMENT INFORMATION

	PNM			TNMP			Corporate and Other			PNMR Consolidated
	(In thousands)
Three Months Ended March 31, 2019
Electric operating revenues	$	269,318		$	80,327		$	—		$	349,645
Cost of energy	99,339			22,287			—			121,626
Utility margin	169,979			58,040			—			228,019
Other operating expenses	106,462			25,241			(5,763		)	125,940
Depreciation and amortization	39,224			20,214			5,918			65,356
Operating income (loss)	24,293			12,585			(155		)	36,723
Interest income	3,656			31			(68		)	3,619
Other income (deductions)	14,358			554			(735		)	14,177
Interest charges	(18,360		)	(8,800		)	(4,474		)	(31,634		)
Segment earnings (loss) before income taxes	23,947			4,370			(5,432		)	22,885
Income taxes (benefit)	1,973			272			(1,022		)	1,223
Segment earnings (loss)	21,974			4,098			(4,410		)	21,662
Valencia non-controlling interest	(2,830		)	—			—			(2,830		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	19,012		$	4,098		$	(4,410	)	$	18,700
At March 31, 2019:
Total Assets	$	5,202,039		$	1,871,780		$	176,939		$	7,250,758
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	PNM			TNMP			Corporate and Other			PNMR Consolidated
	(In thousands)
Three Months Ended March 31, 2018
Electric operating revenues	$	236,232		$	81,646		$	—		$	317,878
Cost of energy	70,802			21,754			—			92,556
Utility margin	165,430			59,892			—			225,322
Other operating expenses	100,511			24,973			(5,016		)	120,468
Depreciation and amortization	36,627			16,387			5,708			58,722
Operating income (loss)	28,292			18,532			(692		)	46,132
Interest income	2,487			—			1,637			4,124
Other income (deductions)	1,217			1,085			79			2,381
Interest charges	(20,830		)	(7,729		)	(4,496		)	(33,055		)
Segment earnings (loss) before income taxes	11,166			11,888			(3,472		)	19,582
Income taxes (benefit)	(348		)	2,475			(1,344		)	783
Segment earnings (loss)	11,514			9,413			(2,128		)	18,799
Valencia non-controlling interest	(3,677		)	—			—			(3,677		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	7,705		$	9,413		$	(2,128	)	$	14,990
At March 31, 2018:
Total Assets	$	4,925,741		$	1,526,434		$	224,218		$	6,676,393
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2019

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2019 and 2018 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	PNM									PNMR
	Unrealized									Fair Value
	Gains on									Adjustment
	Available-for-			Pension						for Cash
	Sale			Liability						Flow
	Securities			Adjustment			Total			Hedges			Total
	(In thousands)
Balance at December 31, 2018	$	1,939		$	(112,361	)	$	(110,422	)	$	1,738		$	(108,684	)
Amounts reclassified from AOCI (pre-tax)	(676		)	1,851			1,175			270			1,445
Income tax impact of amounts reclassified	172			(470		)	(298		)	(68		)	(366		)
Other OCI changes (pre-tax)	7,078			—			7,078			(1,225		)	5,853
Income tax impact of other OCI changes	(1,798		)	—			(1,798		)	311			(1,487		)
Net after-tax change	4,776			1,381			6,157			(712		)	5,445
Balance at March 31, 2019	$	6,715		$	(110,980	)	$	(104,265	)	$	1,026		$	(103,239	)

Balance at December 31, 2017, as originally reported	$	13,169		$	(110,262	)	$	(97,093	)	$	1,153		$	(95,940	)
Cumulative effect adjustment (Note 7)	(11,208		)	—			(11,208		)	—			(11,208		)
Balance at January 1, 2018, as adjusted	1,961			(110,262		)	(108,301		)	1,153			(107,148		)
Amounts reclassified from AOCI (pre-tax)	(2,629		)	1,891			(738		)	(53		)	(791		)
Income tax impact of amounts reclassified	668			(480		)	188			13			201
Other OCI changes (pre-tax)	1,115			—			1,115			1,858			2,973
Income tax impact of other OCI changes	(283		)	—			(283		)	(472		)	(755		)
Net after-tax change	(1,129		)	1,411			282			1,346			1,628
Balance at March 31, 2018	$	832		$	(108,851	)	$	(108,019	)	$	2,499		$	(105,520	)

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

Computation of Earnings Per Share

Information regarding the computation of earnings per share is as follows:

	Three Months Ended
	March 31,
	2019		2018
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	18,700	$	14,990
Average Number of Common Shares:
Outstanding during period	79,654		79,654
Vested awards of restricted stock	239		205
Average Shares – Basic	79,893		79,859
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	78		154
Average Shares – Diluted	79,971		80,013
Net Earnings Per Share of Common Stock:
Basic	$	0.23	$	0.19
Diluted	$	0.23	$	0.19

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Electric Operating Revenues (Tables)

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects alternative revenue program revenues (“ARP”) and other revenues.

	PNM		TNMP		PNMR Consolidated
Three Months Ended March 31, 2019	(In thousands)
Electric Operating Revenues:
Contracts with customers:
Retail electric revenue
Residential	$	107,302	$	30,432	$	137,734
Commercial	85,233		27,429		112,662
Industrial	14,747		5,616		20,363
Public authority	4,711		1,374		6,085
Economy energy service	6,922		—		6,922
Transmission	13,385		14,003		27,388
Miscellaneous	3,641		903		4,544
Total revenues from contracts with customers	235,941		79,757		315,698
Alternative revenue programs	66		570		636
Other electric operating revenues	33,311		—		33,311
Total Electric Operating Revenues	$	269,318	$	80,327	$	349,645

	PNM		TNMP		PNMR Consolidated
Three Months Ended March 31, 2018	(In thousands)
Electric Operating Revenues:
Contracts with customers:
Retail electric revenue
Residential	$	97,169	$	29,266	$	126,435
Commercial	82,849		27,152		110,001
Industrial	13,459		4,305		17,764
Public authority	4,635		1,416		6,051
Economy energy service	7,288		—		7,288
Transmission	12,482		16,508		28,990
Miscellaneous	4,682		2,140		6,822
Total revenues from contracts with customers	222,564		80,787		303,351
Alternative revenue programs	65		859		924
Other electric operating revenues	13,603		—		13,603
Total Electric Operating Revenues	$	236,232	$	81,646	$	317,878

Contract with Customer, Asset and Liability

Changes during the period in the balances of contract liabilities, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, are as follows:

	PNM			TNMP			PNMR Consolidated
	(In thousands)
Balance at December 31, 2018	$	349		$	—		$	349
Consideration received in advance of service to be provided	3,981			1,389			5,370
Deferred revenue earned	(1,349		)	(371		)	(1,720		)
Balance at March 31, 2019	$	2,981		$	1,018		$	3,999

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Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2019

Variable Interest Entities [Abstract]

Summarized Financial Information

Summarized financial information for Valencia is as follows:

	Results of Operations
	Three Months Ended March 31,
	2019			2018
	(In thousands)
Operating revenues	$	4,952		$	4,768
Operating expenses	(2,122		)	(1,091		)
Earnings attributable to non-controlling interest	$	2,830		$	3,677

	Financial Position
	March 31,		December 31,
	2019		2018
	(In thousands)
Current assets	$	2,918	$	2,684
Net property, plant, and equipment	60,712		62,066
Total assets	63,630		64,750
Current liabilities	851		538
Owners’ equity – non-controlling interest	$	62,779	$	64,212

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Fair Value of Derivative and Other Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value of Derivative and Other Financial Instruments [Abstract]

Summary of 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
	March 31, 2019			December 31, 2018
	(In thousands)
Current assets	$	1,086		$	1,083
Deferred charges	2,265			2,511
	3,351			3,594
Current liabilities	(1,150		)	(1,177		)
Long-term liabilities	(2,265		)	(2,511		)
	(3,415		)	(3,688		)
Net	$	(64	)	$	(94	)

Effect of Mark-to-Market on Earnings, Excluding Tax Effects

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
	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
Electric operating revenues	$	28		$	(10	)
Cost of energy	(28		)	12
Total gain	$	—		$	2

Schedule of Net Buy (Sell) Volume Positions

The table below presents PNM’s net buy (sell) volume positions:

	Economic Hedges
	MMBTU	MWh
March 31, 2019	100,000	(400	)
December 31, 2018	100,000	—

Schedule of Gross Realized Gains and Losses

Gains and losses recognized on the Condensed Consolidated Statements of Earnings related to investment securities in the NDT and reclamation trusts are presented in the following table.

	Three Months Ended March 31,
	2019		2018
	(In thousands)
Equity securities:
Net gains from equity securities sold	$	1,387	$	2,828
Net gains from equity securities still held	9,602		136
Total net gains on equity securities	10,989		2,964
Available-for-sale debt securities:
Net gains (losses) on debt securities	3,025		(2,676		)
Net gains on investment securities	$	14,014	$	288

The proceeds and gross realized gains and losses on the disposition of securities held in the NDT and coal mine reclamation trusts 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 $3.4 million and $(1.2) million for the three months ended March 31, 2019 and 2018.

	Three Months Ended
	March 31,
	2019			2018
	(In thousands)
Proceeds from sales	$	74,460		$	626,729
Gross realized gains	$	4,189		$	6,021
Gross realized (losses)	$	(3,170	)	$	(4,677	)

Investments Classified by Contractual Maturity Date

At March 31, 2019, the available-for-sale debt securities held by PNM, had the following final maturities:

	Fair Value
	(In thousands)
Within 1 year	$	13,996
After 1 year through 5 years	68,108
After 5 years through 10 years	68,904
After 10 years through 15 years	9,485
After 15 years through 20 years	12,174
After 20 years	45,695
	$	218,362

Schedule of Investments

Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy along with gross unrealized gains on investments in available-for-sale debt securities.

				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)		Unrealized Gains
	(In thousands)
March 31, 2019
Cash and cash equivalents	$	10,339		$	10,339	$	—		$	—
Equity securities:
Corporate stocks, common	36,025			36,025		—			—
Corporate stocks, preferred	8,138			1,854		6,284			—
Mutual funds and other	78,699			78,688		11			—
Available-for-sale debt securities:
U.S. Government	36,153			25,074		11,079			—		$	1,489
International Government	11,577			46		11,531			—		345
Municipals	49,160			—		49,160			—		1,337
Corporate and other	121,472			842		118,543			2,087		5,831
	$	351,563		$	152,868	$	196,608		$	2,087	$	9,002
Commodity derivative assets	$	3,351		$	—	$	3,351		$	—
Commodity derivative liabilities	(3,415		)	—		(3,415		)	—
Net	$	(64	)	$	—	$	(64	)	$	—
December 31, 2018
Cash and cash equivalents	$	11,472		$	11,472	$	—		$	—
Equity securities:
Corporate stocks, common	32,997			32,997		—			—
Corporate stocks, preferred	7,258			1,654		5,604			—
Mutual funds and other	70,777			70,777		—			—
Available-for-sale debt securities:
U.S. Government	29,503			18,662		10,841			—		$	1,098
International Government	8,435			—		8,435			—		90
Municipals	53,642			—		53,642			—		489
Corporate and other	114,158			588		111,414			2,156		923
	$	328,242		$	136,150	$	189,936		$	2,156	$	2,600
Commodity derivative assets	$	3,594		$	—	$	3,594		$	—
Commodity derivative liabilities	(3,688		)	—		(3,688		)	—
Net	$	(94	)	$	—	$	(94	)	$	—

Summary of Level 3 Measurements

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

	Corporate Debt
	(In thousands)
Balance at December 31, 2018	$	2,156
Actual return on assets sold during the period	(49		)
Actual return on assets still held at period end	54
Purchases	414
Sales	(488		)
Balance at March 31, 2019	$	2,087
Balance at December 31, 2017	$	—
Actual return on assets sold during the period	(3		)
Actual return on assets still held at period end	(11		)
Purchases	2,724
Sales	(359		)
Balance at March 31, 2018	$	2,351

Schedule of Carrying Amount and Fair Value of Items Not Recorded at Fair Value

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

					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
March 31, 2019	(In thousands)
PNMR
Long-term debt	$	2,944,241	$	3,023,159	$	—	$	3,023,159	$	—
Other investments	$	299	$	299	$	299	$	—	$	—
PNM
Long-term debt	$	1,706,873	$	1,744,864	$	—	$	1,744,864	$	—
Other investments	$	93	$	93	$	93	$	—	$	—
TNMP
Long-term debt	$	798,941	$	838,705	$	—	$	838,705	$	—
Other investments	$	206	$	206	$	206	$	—	$	—
December 31, 2018
PNMR
Long-term debt	$	2,670,111	$	2,703,810	$	—	$	2,703,810	$	—
Other investments	$	297	$	297	$	297	$	—	$	—
PNM
Long-term debt	$	1,656,490	$	1,668,736	$	—	$	1,668,736	$	—
Other investments	$	91	$	91	$	91	$	—	$	—
TNMP
Long-term debt	$	575,398	$	597,236	$	—	$	597,236	$	—
Other investments	$	206	$	206	$	206	$	—	$	—

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Stock-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Activity

The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options:

	Three Months Ended March 31,
Restricted Stock	2019		2018
Weighted-average grant date fair value	$	36.48	$	29.03
Total fair value of restricted shares that vested (in thousands)	$	5,314	$	7,162
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)	$	2,582	$	2,711

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

	Three Months Ended March 31,
Restricted Shares and Performance Based Shares	2019			2018
Expected quarterly dividends per share	$	0.2900		$	0.2650
Risk-free interest rate	2.50		%	2.39		%
Market-Based Shares
Dividend yield	2.59		%	2.96		%
Expected volatility	19.55		%	19.12		%
Risk-free interest rate	2.51		%	2.36		%

The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the three months endedMarch 31, 2019:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2018	166,651		$	32.93	81,000		$	11.94
Granted	114,611		$	36.48	—		$	—
Exercised	(118,427	)	$	30.97	(78,000	)	$	11.92
Forfeited	—		$	—	—		$	—
Expired	—		$	—	—		$	—
Outstanding at March 31, 2019	162,835		$	36.86	3,000		$	12.38

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Financing (Tables)

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Schedule of Maturities of Long-term Debt

Information concerning the funding dates, maturities and interest rates on the TNMP 2019 Bonds issued in March 2019 and to be issued on or before July 1, 2019 is as follows:

Funding Date	Maturity Date	Principal Amount		Interest Rate
		(In millions)
March 29, 2019	March 29, 2034	$	75.0	3.79	%
March 29, 2019	March 29, 2039	75.0		3.92	%
March 29, 2019	March 29, 2044	75.0		4.06	%
		225.0
July 1, 2019	July 1, 2029	80.0		3.60	%
		$	305.0

Schedule of Short-term Debt

Short-term debt outstanding consisted of:

	March 31,		December 31,
Short-term Debt	2019		2018
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	—	$	32,400
PNM 2017 New Mexico Credit Facility	—		10,000
	—		42,400
TNMP Revolving Credit Facility	—		17,500
PNMR:
PNMR Revolving Credit Facility	62,200		20,000
PNMR 2018 One-Year Term Loan	150,000		150,000
PNMR Development Revolving Credit Facility	11,600		6,000
	$	223,800	$	235,900

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Pension and Other Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Schedule of Net Benefit Costs

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

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2019			2018			2019			2018			2019		2018
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	13		$	21		$	—	$	—
Interest cost	6,294			6,068			829			860			162		155
Expected return on plan assets	(8,527		)	(8,672		)	(1,318		)	(1,353		)	—		—
Amortization of net (gain) loss	3,880			4,087			169			588			79		90
Amortization of prior service cost	(241		)	(241		)	(99		)	(416		)	—		—
Net periodic benefit cost	$	1,406		$	1,242		$	(406	)	$	(300	)	$	241	$	245

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

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2019			2018			2019			2018			2019		2018
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	13		$	33		$	—	$	—
Interest cost	672			656			113			119			8		7
Expected return on plan assets	(967		)	(991		)	(129		)	(135		)	—		—
Amortization of net (gain) loss	235			272			(110		)	(56		)	4		4
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost	$	(60	)	$	(63	)	$	(113	)	$	(39	)	$	12	$	11

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Regulatory and Rate Matters (Tables)

3 Months Ended

Mar. 31, 2019

Regulated Operations [Abstract]

Schedule of Rate Increases for Transmission Costs

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)
September 8, 2016	$	9.5	$	1.8
March 14, 2017	30.2		4.8
September 13, 2017	27.5		4.7
March 27, 2018	32.0		0.6
March 21, 2019	111.8		14.3

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Lease Commitments (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Assets and Liabilities, Lessee

Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below:

	March 31, 2019						January 1, 2019
	PNM		TNMP		PNMR Consolidated		PNM		TNMP		PNMR Consolidated
	(In thousands)
Operating leases:
Operating lease assets, net of amortization	$	137,756	$	12,160	$	150,426	$	143,816	$	12,942	$	157,440
Current portion of operating lease liabilities	22,762		3,023		26,197		21,589		3,132		25,189
Long-term portion of operating lease liabilities	115,436		9,088		124,937		124,891		9,787		135,174

Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below:

	March 31, 2019
	PNM			TNMP			PNMR Consolidated
	(In thousands)
Financing leases:
Non-utility property	$	1,635		$	1,268		$	2,904
Accumulated depreciation	(37		)	(40		)	(78		)
Non-utility property, net	$	1,598		$	1,228		$	2,826
Other current liabilities	$	233		$	217		$	450
Other deferred credits	1,083			1,006			2,089

Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below:

	March 31, 2019
	PNM		TNMP		PNMR Consolidated
Weighted average remaining lease term (In years):
Operating leases	7.18		4.67		6.95
Financing leases	5.72		5.75		5.74
Weighted average discount rate:
Operating leases	3.88	%	3.88	%	3.88	%
Financing leases	4.34	%	4.55	%	4.43	%

Lease, Cost

Information for the components of lease expense is as follows:

	Three Months Ended March 31, 2019
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Total operating lease expense	$	7,231	$	241	$	7,611
Financing lease expense:
Amortization of right-of-use assets	66		58		125
Interest on lease liabilities	16		17		32
Total financing lease expense	82		75		157
Variable lease expense	—		—		—
Short-term lease expense	74		3		94
Total lease expense for the period	$	7,387	$	319	$	7,862

Schedule of Leases, Supplemental Cash Flows

Supplemental cash flow information related to the Company’s leases is as follows:

	Three Months Ending March 31, 2019
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	9,452	$	284	$	9,891
Operating cash flows from financing leases	16		17		32
Finance cash flows from financing leases	25		33		58
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	143,816	$	12,942	$	157,440
Financing leases	1,635		1,268		2,904

Lessee, Operating Lease, Liability, Maturity

Future expected lease payments as of March 31, 2019 and December 31, 2018 are shown below:

	As of March 31, 2019
	PNM				TNMP				PNMR Consolidated
	Financing		Operating		Financing		Operating		Financing		Operating
	(In thousands)
Remainder of 2019	$	266	$	17,917	$	209	$	2,622	$	475	$	20,980
2020	344		27,045		269		2,993		613		30,555
2021	332		26,505		259		2,398		591		29,158
2022	319		26,235		249		1,846		568		28,255
2023	307		17,457		181		1,281		488		18,879
Later years	224		42,328		214		1,151		438		43,490
Total minimum lease payments	1,792		157,487		1,381		12,291		3,173		171,317
Less: Imputed interest	476		19,289		158		180		634		20,183
Lease liabilities as of March 31, 2019	$	1,316	$	138,198	$	1,223	$	12,111	$	2,539	$	151,134

Finance Lease, Liability, Maturity

Future expected lease payments as of March 31, 2019 and December 31, 2018 are shown below:

	As of March 31, 2019
	PNM				TNMP				PNMR Consolidated
	Financing		Operating		Financing		Operating		Financing		Operating
	(In thousands)
Remainder of 2019	$	266	$	17,917	$	209	$	2,622	$	475	$	20,980
2020	344		27,045		269		2,993		613		30,555
2021	332		26,505		259		2,398		591		29,158
2022	319		26,235		249		1,846		568		28,255
2023	307		17,457		181		1,281		488		18,879
Later years	224		42,328		214		1,151		438		43,490
Total minimum lease payments	1,792		157,487		1,381		12,291		3,173		171,317
Less: Imputed interest	476		19,289		158		180		634		20,183
Lease liabilities as of March 31, 2019	$	1,316	$	138,198	$	1,223	$	12,111	$	2,539	$	151,134

Schedule of Future Minimum Rental Payments for Operating Leases

	As of December 31, 2018
	Operating leases
	PNM		TNMP		PNMR Consolidated
	(In thousands)
Remainder of 2019	$	27,691	$	3,664	$	31,772
2020	27,000		3,102		30,404
2021	26,462		2,324		29,012
2022	26,217		1,795		28,175
2023	17,447		1,279		18,868
Later years	42,329		1,150		43,489
Total minimum lease payments	167,146		13,314		181,720

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2019

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD:

	Three Months Ended
	March 31,
	2019		2018
	(In thousands)
Services billings:
PNMR to PNM	$	26,826	$	23,679
PNMR to TNMP	10,058		8,365
PNM to TNMP	75		86
TNMP to PNMR	35		35
PNMR to NMRD	41		78
Renewable energy purchases:
PNM from NMRD	625		370
Interconnection billings:
PNM to NMRD	—		—
PNM to PNMR	—		—
Interest billings:
PNMR to PNM	933		62
PNM to PNMR	72		66
PNMR to TNMP	32		8
Income tax sharing payments:
PNMR to PNM	—		—
TNMP to PNMR	—		—

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Significant Accounting Policies and Responsibility for Financial Statements (Details)	3 Months Ended
	Mar. 31, 2019 USD ($) MW	Mar. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Business Acquisition [Line Items]
Payment defaults under agreements	$ 0
Dividends declared on common stock	23,099,000	$ 21,108,000
Revenues	349,645,000	317,878,000
Construction work in progress	225,485,000		$ 194,427,000
Owners' equity	$ 1,684,679,000		1,688,382,000
NMRD
Business Acquisition [Line Items]
Renewable energy capacity in operating (in mw) | MW	33.9
Texas-New Mexico Power Company
Business Acquisition [Line Items]
Dividends declared on common stock	$ 10,713,000	1,024,000
Revenues	80,327,000	81,646,000
Net earnings	4,098,000	9,413,000
Construction work in progress	75,332,000		51,459,000
Owners' equity	$ 667,478,000	642,794,000	$ 674,093,000	$ 634,405,000
PNMR Development | NMRD
Business Acquisition [Line Items]
Ownership percentage	50.00%
AEP OnSite Partners | NMRD
Business Acquisition [Line Items]
Ownership percentage	50.00%
NMRD
Business Acquisition [Line Items]
Revenues	$ 700,000	400,000
Net earnings	(100,000)	100,000
Cash	8,000,000	2,600,000
Construction work in progress	65,200,000	50,800,000
Accounts payable	6,100,000	200,000
Owners' equity	67,100,000	53,200,000
PNMR Development and AEP OnSite | NMRD
Business Acquisition [Line Items]
Contribution to construction activities	$ 7,000,000	$ 5,000,000

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Segment Information - Summarized Financial Information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($) segment	Mar. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)
Segment Reporting Information [Line Items]
Number of operating segments | segment	1
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	$ 349,645	$ 317,878
Utility margin	228,019	225,322
Other operating expenses	125,940	120,468
Depreciation and amortization	65,356	58,722
Operating income	36,723	46,132
Interest income	3,619	4,124
Other income (deductions)	14,177	2,381
Interest charges	(31,634)	(33,055)
Earnings before Income Taxes	22,885	19,582
Income taxes (benefit)	1,223	783
Net Earnings	21,662	18,799
Valencia non-controlling interest	(2,830)	(3,677)
Subsidiary preferred stock dividends	(132)	(132)
Net Earnings Available for PNM Common Stock	18,700	14,990
Total Assets	7,250,758	6,676,393	$ 6,865,551
Goodwill	278,297	278,297	$ 278,297
PNM
Segment Reporting Information, Profit (Loss) [Abstract]
Utility margin	169,979	165,430
Other operating expenses	106,462	100,511
Depreciation and amortization	39,224	36,627
Operating income	24,293	28,292
Interest income	3,656	2,487
Other income (deductions)	14,358	1,217
Interest charges	(18,360)	(20,830)
Earnings before Income Taxes	23,947	11,166
Income taxes (benefit)	1,973	(348)
Net Earnings	21,974	11,514
Valencia non-controlling interest	(2,830)	(3,677)
Subsidiary preferred stock dividends	(132)	(132)
Net Earnings Available for PNM Common Stock	19,012	7,705
Total Assets	5,202,039	4,925,741
Goodwill	51,632	51,632
TNMP
Segment Reporting Information, Profit (Loss) [Abstract]
Utility margin	58,040	59,892
Other operating expenses	25,241	24,973
Depreciation and amortization	20,214	16,387
Operating income	12,585	18,532
Interest income	31	0
Other income (deductions)	554	1,085
Interest charges	(8,800)	(7,729)
Earnings before Income Taxes	4,370	11,888
Income taxes (benefit)	272	2,475
Net Earnings	4,098	9,413
Valencia non-controlling interest	0	0
Subsidiary preferred stock dividends	0	0
Net Earnings Available for PNM Common Stock	4,098	9,413
Total Assets	1,871,780	1,526,434
Goodwill	226,665	226,665
Corporate and Other
Segment Reporting Information, Profit (Loss) [Abstract]
Utility margin	0	0
Other operating expenses	(5,763)	(5,016)
Depreciation and amortization	5,918	5,708
Operating income	(155)	(692)
Interest income	(68)	1,637
Other income (deductions)	(735)	79
Interest charges	(4,474)	(4,496)
Earnings before Income Taxes	(5,432)	(3,472)
Income taxes (benefit)	(1,022)	(1,344)
Net Earnings	(4,410)	(2,128)
Valencia non-controlling interest	0	0
Subsidiary preferred stock dividends	0	0
Net Earnings Available for PNM Common Stock	(4,410)	(2,128)
Total Assets	176,939	224,218
Goodwill	0	0
Electricity
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	349,645	317,878
Cost of energy	121,626	92,556
Electricity | PNM
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	269,318	236,232
Cost of energy	99,339	70,802
Electricity | TNMP
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	80,327	81,646
Cost of energy	22,287	21,754
Electricity | Corporate and Other
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	0	0
Cost of energy	$ 0	$ 0

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Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Jan. 01, 2018
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	$ 1,752,594	$ 1,761,448
Balance, as adjusted			$ 1,761,448
Amounts reclassified from AOCI (pre-tax)	1,445	(791)
Income tax impact of amounts reclassified	(366)	201
Other OCI changes (pre-tax)	5,853	2,973
Income tax impact of other OCI changes	(1,487)	(755)
Total Other Comprehensive Income	5,445	1,628
Ending balance	1,747,458	1,749,014
Total
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(108,684)	(95,940)
Cumulative effect adjustment (Note 7)			(11,208)
Balance, as adjusted			(107,148)
Total Other Comprehensive Income	5,445	1,628
Ending balance	(103,239)	(105,520)
Fair Value Adjustment for Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	1,738
Amounts reclassified from AOCI (pre-tax)	270
Income tax impact of amounts reclassified	(68)
Other OCI changes (pre-tax)	(1,225)
Income tax impact of other OCI changes	311
Total Other Comprehensive Income	(712)
Ending balance	1,026
Fair Value Adjustment for Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance		1,153
Balance, as adjusted			1,153
Amounts reclassified from AOCI (pre-tax)		(53)
Income tax impact of amounts reclassified		13
Other OCI changes (pre-tax)		1,858
Income tax impact of other OCI changes		(472)
Total Other Comprehensive Income		1,346
Ending balance		2,499
PNM
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	1,461,571	1,488,369
Balance, as adjusted			1,488,369
Amounts reclassified from AOCI (pre-tax)	1,175	(738)
Income tax impact of amounts reclassified	(298)	188
Other OCI changes (pre-tax)	7,078	1,115
Income tax impact of other OCI changes	(1,798)	(283)
Total Other Comprehensive Income	6,157	282
Ending balance	1,485,307	1,495,561
PNM | Total
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(110,422)	(97,093)
Cumulative effect adjustment (Note 7)			(11,208)
Balance, as adjusted			(108,301)
Total Other Comprehensive Income	6,157	282
Ending balance	(104,265)	(108,019)
PNM | Unrealized Gains on Available-for-Sale Securities
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	1,939	13,169
Cumulative effect adjustment (Note 7)			(11,208)
Balance, as adjusted			1,961
Amounts reclassified from AOCI (pre-tax)	(676)	(2,629)
Income tax impact of amounts reclassified	172	668
Other OCI changes (pre-tax)	7,078	1,115
Income tax impact of other OCI changes	(1,798)	(283)
Total Other Comprehensive Income	4,776	(1,129)
Ending balance	6,715	832
PNM | Pension Liability Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(112,361)	(110,262)
Balance, as adjusted			$ (110,262)
Amounts reclassified from AOCI (pre-tax)	1,851	1,891
Income tax impact of amounts reclassified	(470)	(480)
Total Other Comprehensive Income	1,381	1,411
Ending balance	$ (110,980)	$ (108,851)

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share [Abstract]
Net Earnings Available for PNM Common Stock	$ 18,700	$ 14,990
Average Number of Common Shares:
Outstanding during period (in shares)	79,654	79,654
Vested awards of restricted stock (in shares)	239	205
Average Shares – Basic (in shares)	79,893	79,859
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock (in shares)	78	154
Average Shares – Diluted (in shares)	79,971	80,013
Net Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 0.23	$ 0.19
Diluted (in dollars per share)	$ 0.23	$ 0.19

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Electric Operating Revenues - Narrative (Details)	Mar. 31, 2019 USD ($) utility	Dec. 31, 2018 USD ($)
Disaggregation of Revenue [Line Items]
Number of regulated utilities | utility	2
Contract assets	$ 0	$ 0
Customer contracts | PNM
Disaggregation of Revenue [Line Items]
Accounts receivable	$ 65,200,000	$ 61,700,000

XML

Electric Operating Revenues - Disaggregation of revenues (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	$ 315,698	$ 303,351
Revenues	349,645	317,878
PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	235,941	222,564
Revenues	269,318	236,232
TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	79,757	80,787
Revenues	80,327	81,646
Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	137,734	126,435
Residential | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	107,302	97,169
Residential | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	30,432	29,266
Commercial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	112,662	110,001
Commercial | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	85,233	82,849
Commercial | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	27,429	27,152
Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	20,363	17,764
Industrial | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	14,747	13,459
Industrial | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	5,616	4,305
Public authority
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	6,085	6,051
Public authority | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	4,711	4,635
Public authority | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,374	1,416
Economy energy service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	6,922	7,288
Economy energy service | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	6,922	7,288
Economy energy service | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	27,388	28,990
Transmission | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	13,385	12,482
Transmission | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	14,003	16,508
Miscellaneous
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	4,544	6,822
Miscellaneous | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	3,641	4,682
Miscellaneous | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	903	2,140
Alternative revenue programs
Disaggregation of Revenue [Line Items]
Revenues	636	924
Alternative revenue programs | PNM
Disaggregation of Revenue [Line Items]
Revenues	66	65
Alternative revenue programs | TNMP
Disaggregation of Revenue [Line Items]
Revenues	570	859
Other electric operating revenues
Disaggregation of Revenue [Line Items]
Revenues	33,311	13,603
Other electric operating revenues | PNM
Disaggregation of Revenue [Line Items]
Revenues	33,311	13,603
Other electric operating revenues | TNMP
Disaggregation of Revenue [Line Items]
Revenues	$ 0	$ 0

XML

Electric Operating Revenues - Changes in contract liabilities (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Change In Contract With Customer Liability [Roll Forward]
Beginning balance	$ 349
Consideration received in advance of service to be provided	5,370
Deferred revenue earned	(1,720)
Ending balance	3,999
PNM
Change In Contract With Customer Liability [Roll Forward]
Beginning balance	349
Consideration received in advance of service to be provided	3,981
Deferred revenue earned	(1,349)
Ending balance	2,981
TNMP
Change In Contract With Customer Liability [Roll Forward]
Beginning balance	0
Consideration received in advance of service to be provided	1,389
Deferred revenue earned	(371)
Ending balance	$ 1,018

XML

Variable Interest Entities (Details)		3 Months Ended
	Feb. 01, 2016 USD ($)	Mar. 31, 2019 USD ($) MW	Mar. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	May 22, 2018 USD ($)	Jan. 31, 2016 USD ($)
Results of Operations
Earnings attributable to non-controlling interest		$ 2,830,000	$ 3,677,000
Financial Position
Current assets		457,073,000		$ 302,524,000
Total assets		7,250,758,000	6,676,393,000	6,865,551,000
Current liabilities		664,133,000		512,453,000
Owners’ equity – non-controlling interest		62,779,000		64,212,000
PNM
Results of Operations
Earnings attributable to non-controlling interest		2,830,000	3,677,000
Financial Position
Current assets		255,419,000		270,319,000
Total assets		5,202,039,000		5,035,883,000
Current liabilities		195,667,000		223,023,000
Owners’ equity – non-controlling interest		62,779,000		64,212,000
PNM | Valencia
Variable Interest Entity [Line Items]
Payment for fixed costs		4,900,000	4,900,000
Payment for variable costs		$ 100,000	300,000
Long-term contract option to purchase, ownership percentage (up to)		50.00%
Long-term contract option to purchase, purchase price - percentage of adjusted NBV		50.00%
Long-term contract option to purchase, purchase price - percentage of FMV		50.00%
Results of Operations
Operating revenues		$ 4,952,000	4,768,000
Operating expenses		(2,122,000)	(1,091,000)
Earnings attributable to non-controlling interest		2,830,000	$ 3,677,000
Financial Position
Current assets		2,918,000		2,684,000
Net property, plant, and equipment		60,712,000		62,066,000
Total assets		63,630,000		64,750,000
Current liabilities		851,000		538,000
Owners’ equity – non-controlling interest		$ 62,779,000		$ 64,212,000
PNM | Valencia | Purchased through May 2028
Variable Interest Entity [Line Items]
Number of megawatts purchased (in megawatts) | MW		158
NM Capital | San Juan Generating Station | Coal supply
Variable Interest Entity [Line Items]
Loan agreement among several entities	$ 125,000,000.0
Cash used to support bank letter or credit arrangement		$ 30,300,000				$ 30,300,000
NM Capital | San Juan Coal Company, Westmoreland | Coal supply
Variable Interest Entity [Line Items]
Repayment of line of credit					$ 50,100,000

XML

Fair Value of Derivative and Other Financial Instruments - Overview and Commodity Derivatives (Details)	Mar. 31, 2019 USD ($) MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Derivatives, Fair Value [Line Items]
Obligations to return cash	$ 900,000	$ 1,000,000
PNM
Derivatives, Fair Value [Line Items]
Expected exposure to market risk (in megawatts) | MW	65
Power to be sold to third party (in megawatts) | MW	36
Amounts recognized for right to reclaim cash	$ 0	0
Cash collateral under margin arrangements	1,000,000	1,000,000
PNM | Designated as Hedging Instrument | Commodity derivatives
Derivatives, Fair Value [Line Items]
Current assets	1,086,000	1,083,000
Deferred charges	2,265,000	2,511,000
Derivative asset	3,351,000	3,594,000
Current liabilities	(1,150,000)	(1,177,000)
Long-term liabilities	(2,265,000)	(2,511,000)
Derivative liability	(3,415,000)	(3,688,000)
Net	(64,000)	(94,000)
PNM | Designated as Hedging Instrument | Commodity derivatives | Fuel and purchased power costs
Derivatives, Fair Value [Line Items]
Current assets	0		$ 0
PNM | Designated as Hedging Instrument | Commodity derivatives | Hazard sharing arrangement
Derivatives, Fair Value [Line Items]
Derivative asset	$ 3,300,000	$ 3,600,000
Tri-State | PNM
Derivatives, Fair Value [Line Items]
Power to be sold to third party (in megawatts) | MW	100

XML

Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - PNM - Designated as Hedging Instrument - Commodity derivatives - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Total gain	$ 0	$ 2
Electric operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Total gain	28	(10)
Cost of energy
Derivative Instruments, Gain (Loss) [Line Items]
Total gain	$ (28)	$ 12

XML

Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2019 USD ($) MMBTU MWh	Dec. 31, 2018 USD ($) MMBTU MWh
Derivative [Line Items]
Contract in a liability position | $	$ 0	$ 0
PNM | Commodity derivatives | Fair value hedging | Buy
Derivative [Line Items]
Economic Hedges (in mmbtu and mwh) | MMBTU	100,000	100,000
PNM | Commodity derivatives | Fair value hedging | Sell
Derivative [Line Items]
Economic Hedges (in mmbtu and mwh) | MWh	400	0

XML

Fair Value of Derivative and Other Financial Instruments - Investments in NDT (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Equity securities:
Net gains from equity securities sold	$ 1,387	$ 2,828
Net gains from equity securities still held	9,602	136
Total net gains on equity securities	10,989	2,964
Available-for-sale debt securities:
Net gains (losses) on debt securities	3,025	(2,676)
Net gains on investment securities	$ 14,014	$ 288

XML

Fair Value of Derivative and Other Financial Instruments - Available for Sale Securities (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Jan. 01, 2018
Debt Securities, Available-for-sale [Line Items]
Debt securities, available-for-sale, unrealized loss position	$ 0
Other than temporary impairments	0
PNM
Debt Securities, Available-for-sale [Line Items]
(Increase)/decrease in other than temporary losses of available-for-sale securities, net portion recognized in earnings	3,400,000	$ (1,200,000)
Proceeds from sales	74,460,000	626,729,000
Gross realized gains	4,189,000	6,021,000
Gross realized (losses)	(3,170,000)	$ (4,677,000)
Recurring | PNM
Debt Securities, Available-for-sale [Line Items]
Available-for-sale debt securities	351,563,000		$ 328,242,000
Nuclear Decommissioning Trust | Recurring | PNM
Debt Securities, Available-for-sale [Line Items]
Available-for-sale debt securities	308,000,000		287,100,000
Mine Reclamation Trust | Recurring | PNM
Debt Securities, Available-for-sale [Line Items]
Available-for-sale debt securities	$ 43,600,000		$ 41,100,000
Retained Earnings
Debt Securities, Available-for-sale [Line Items]
Cumulative effect adjustment (Note 7)				$ 11,208,000
Retained Earnings | PNM
Debt Securities, Available-for-sale [Line Items]
Cumulative effect adjustment (Note 7)				11,208,000
Accounting Standards Update 2016-01 | Retained Earnings
Debt Securities, Available-for-sale [Line Items]
Cumulative effect adjustment (Note 7)				$ 11,200,000

XML

Fair Value of Derivative and Other Financial Instruments - Maturities of Debt Securities (Details) - PNMR and PNM $ in Thousands	Mar. 31, 2019 USD ($)
Available-for-Sale
Within 1 year	$ 13,996
After 1 year through 5 years	68,108
After 5 years through 10 years	68,904
After 10 years through 15 years	9,485
After 15 years through 20 years	12,174
After 20 years	45,695
Available-for-sale debt securities	$ 218,362

XML

Fair Value of Derivative and Other Financial Instruments - Items Recorded and Presented by Level of Hierarchy (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfers between levels	$ 0	$ 0
Long-term debt	3,023,159,000	2,703,810,000
Other investments	299,000	297,000
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	299,000	297,000
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	3,023,159,000	2,703,810,000
Other investments	0	0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	0	0
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,944,241,000	2,670,111,000
Other investments	299,000	297,000
PNM
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,744,864,000	1,668,736,000
Other investments	93,000	91,000
PNM | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	93,000	91,000
PNM | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,744,864,000	1,668,736,000
Other investments	0	0
PNM | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	0	0
PNM | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,706,873,000	1,656,490,000
Other investments	93,000	91,000
TNMP
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	838,705,000	597,236,000
Other investments	206,000	206,000
TNMP | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	206,000	206,000
TNMP | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	838,705,000	597,236,000
Other investments	0	0
TNMP | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	0	0
TNMP | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	798,941,000	575,398,000
Other investments	206,000	206,000
Recurring | PNM
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	351,563,000	328,242,000
Recurring | PNM | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	152,868,000	136,150,000
Recurring | PNM | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	196,608,000	189,936,000
Recurring | PNM | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	2,087,000	2,156,000
Investments, unrealized gain	9,002,000	2,600,000
Recurring | PNM | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	3,351,000	3,594,000
Commodity derivative liabilities	(3,415,000)	(3,688,000)
Net	(64,000)	(94,000)
Recurring | PNM | Commodity derivatives | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	0	0
Commodity derivative liabilities	0	0
Net	0	0
Recurring | PNM | Commodity derivatives | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	3,351,000	3,594,000
Commodity derivative liabilities	(3,415,000)	(3,688,000)
Net	(64,000)	(94,000)
Recurring | PNM | Commodity derivatives | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	0	0
Commodity derivative liabilities	0	0
Net	0	0
Recurring | PNM | Cash and cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	10,339,000	11,472,000
Recurring | PNM | Cash and cash equivalents | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	10,339,000	11,472,000
Recurring | PNM | Cash and cash equivalents | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	0	0
Recurring | PNM | Cash and cash equivalents | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	0	0
Recurring | PNM | Corporate stocks, common
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	36,025,000	32,997,000
Recurring | PNM | Corporate stocks, common | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	36,025,000	32,997,000
Recurring | PNM | Corporate stocks, common | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	0	0
Recurring | PNM | Corporate stocks, common | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	0	0
Recurring | PNM | Corporate stocks, preferred
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	8,138,000	7,258,000
Recurring | PNM | Corporate stocks, preferred | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	1,854,000	1,654,000
Recurring | PNM | Corporate stocks, preferred | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	6,284,000	5,604,000
Recurring | PNM | Corporate stocks, preferred | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	0	0
Recurring | PNM | Mutual funds and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	78,699,000	70,777,000
Recurring | PNM | Mutual funds and other | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	78,688,000	70,777,000
Recurring | PNM | Mutual funds and other | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	11,000	0
Recurring | PNM | Mutual funds and other | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	0	0
Recurring | PNM | Corporate stocks, common | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, unrealized gain
Recurring | PNM | Corporate stocks, preferred | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, unrealized gain
Recurring | PNM | Mutual funds and other | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, unrealized gain
Recurring | PNM | U.S. Government
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	36,153,000	29,503,000
Recurring | PNM | U.S. Government | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	25,074,000	18,662,000
Recurring | PNM | U.S. Government | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	11,079,000	10,841,000
Recurring | PNM | U.S. Government | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	0	0
Investments, unrealized gain	1,489,000	1,098,000
Recurring | PNM | International Government
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	11,577,000	8,435,000
Recurring | PNM | International Government | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	46,000	0
Recurring | PNM | International Government | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	11,531,000	8,435,000
Recurring | PNM | International Government | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	0	0
Investments, unrealized gain	345,000	90,000
Recurring | PNM | Municipals
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	49,160,000	53,642,000
Recurring | PNM | Municipals | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	0	0
Recurring | PNM | Municipals | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	49,160,000	53,642,000
Recurring | PNM | Municipals | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	0	0
Investments, unrealized gain	1,337,000	489,000
Recurring | PNM | Corporate and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	121,472,000	114,158,000
Recurring | PNM | Corporate and other | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	842,000	588,000
Recurring | PNM | Corporate and other | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	118,543,000	111,414,000
Recurring | PNM | Corporate and other | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	2,087,000	2,156,000
Investments, unrealized gain	$ 5,831,000	$ 923,000

XML

Fair Value of Derivative and Other Financial Instruments - Reconciliation of changes in Level 3 fair value measurements (Details) - Corporate Debt - Level 3 - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning balance	$ 2,156	$ 0
Actual return on assets sold during the period	(49)	(3)
Actual return on assets still held at period end	54	(11)
Purchases	414	2,724
Sales	(488)	(359)
Ending balance	$ 2,087	$ 2,351

XML

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	1 year
Restricted Stock, Shares
Expired (in shares)	0
Restricted Stock, Weighted- Average Grant Date Fair Value
Expired (in dollars per share)	$ 0.00
Stock Options, Shares
Outstanding at beginning of period (in shares)	81,000
Granted (in shares)	0
Exercised (in shares)	(78,000)
Forfeited (in shares)	0
Expired (in shares)	0
Outstanding at end of period (in shares)	3,000
Stock Options, Weighted- Average Exercise Price
Outstanding at beginning of period (in dollars per share)	$ 11.94
Granted (in dollars per share)	0.00
Exercised (in dollars per share)	11.92
Forfeited (in dollars per share)	0.00
Expired (in dollars per share)	0.00
Outstanding at end of period (in dollars per share)	12.38
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value of options granted (in dollars per share)	$ 0.00	$ 0.00
Total fair value of options that vested	$ 0	$ 0
Total intrinsic value of options exercised	2,582	$ 2,711
Chairman, President, and Chief Executive Officer | Common Stock | Achieves a specific performance target by the end of 2019 and she remains an employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return (in shares)				53,859
Chairman, President, and Chief Executive Officer | Common Stock | Achieves a specific performance target by the end of 2017 and she remains an employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return (in shares)				17,953
Restricted Shares and Performance Based Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized expense related to stock awards	$ 6,500
Period of time stock expense is expected to be recognized	1 year 8 months 26 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected quarterly dividends per share (in dollars per share)	$ 0.2900	$ 0.2650
Risk-free interest rate	2.50%	2.39%
Restricted Stock
Restricted Stock, Shares
Outstanding at beginning of period (in shares)	166,651
Granted (in shares)	114,611
Exercised (in shares)	(118,427)
Forfeited (in shares)	0
Expired (in shares)	0
Outstanding at end of period (in shares)	162,835
Restricted Stock, Weighted- Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 32.93
Granted (in dollars per share)	36.48	$ 29.03
Exercised (in dollars per share)	30.97
Forfeited (in dollars per share)	0.00
Expired (in dollars per share)	0.00
Outstanding at end of period (in dollars per share)	$ 36.86
Stock Options, Shares
Expired (in shares)	0
Stock Options, Weighted- Average Exercise Price
Expired (in dollars per share)	$ 0.00
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value (in dollars per share)	$ 36.48	$ 29.03
Total fair value of restricted shares that vested	$ 5,314	$ 7,162
Performance Shares | Executive
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares awarded in year one (in shares)	130,302		47,279
Weighted percentage assigned to achieving market targets			40.00%
Weighted percentage assigned to achieving performance targets			60.00%
Maximum number of shares awarded in year two (in shares)	146,941
Maximum number of shares in year three (in shares)	135,678
Performance period	3 years
Market-Based Shares
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Risk-free interest rate	2.51%	2.36%
Dividend yield	2.59%	2.96%
Expected volatility	19.55%	19.12%
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of stock options outstanding	$ 100
Weighted-average remaining contract life	1 year
Number of outstanding stock options with an exercise price greater than the closing price (in shares)	0
Performance Equity Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Vesting rate	100.00%

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Financing - Financing Activities (Details) - USD ($)				3 Months Ended		6 Months Ended
	Apr. 01, 2019	Jan. 18, 2019	Apr. 09, 2018	Mar. 31, 2019	Mar. 31, 2018	Jun. 30, 2018	Jul. 01, 2019	Mar. 29, 2019	Feb. 26, 2019	Dec. 31, 2018	Jul. 25, 2018	Jul. 20, 2017	Oct. 21, 2016
Debt Instrument [Line Items]
Interest charges				$ 31,634,000	$ 33,055,000
Other deferred credits				$ 169,372,000						$ 167,668,000
PNMR 2016 Two-Year Term Loan
Debt Instrument [Line Items]
Variable interest rate				3.29%
Term loans				$ 50,000,000
Term of loan				2 years
PNM
Debt Instrument [Line Items]
Interest charges				$ 18,360,000	20,830,000
Other deferred credits				$ 215,004,000						215,737,000
PNM | PNM 2019 Term Loan
Debt Instrument [Line Items]
Aggregate principal amount		$ 250,000,000.0
PNM | Maximum
Debt Instrument [Line Items]
Maturity term over which financings require regulator approval (more than)				18 months
Texas-New Mexico Power Company
Debt Instrument [Line Items]
Interest charges				$ 8,800,000	$ 7,729,000
Other deferred credits				$ 3,729,000						$ 2,908,000
Texas-New Mexico Power Company | TNMP 2019 Bond Purchase Agreement
Debt Instrument [Line Items]
Aggregate principal amount								$ 225,000,000	$ 305,000,000.0
Texas-New Mexico Power Company | First Mortgage Bonds Due 2019, Series 2009A, at 9 point 50 percent
Debt Instrument [Line Items]
Extinguishment of debt		$ 172,300,000
Stated interest rate		9.50%
Line of credit
Debt Instrument [Line Items]
Ratio of debt to capital (less than or equal to)				65.00%		70.00%
Letter of credit | PNMR | JPM LOC Facility
Debt Instrument [Line Items]
Aggregate principal amount													$ 30,300,000.0
PNM 2019 Term Loan
Debt Instrument [Line Items]
Interest rate at period end				3.13%
Unsecured Debt | Texas-New Mexico Power Company | First Mortgage Bonds Due 2019, Series 2009A, at 9 point 50 percent
Debt Instrument [Line Items]
Extinguishment of debt	$ 172,300,000
Stated interest rate	9.50%
Mortgages | Texas-New Mexico Power Company | First Mortgage Bonds 3.79 Percent Due 2034
Debt Instrument [Line Items]
Aggregate principal amount								$ 75,000,000
Stated interest rate								3.79%
Mortgages | Texas-New Mexico Power Company | First Mortgage Bonds 3.92 Percent Due 2039
Debt Instrument [Line Items]
Aggregate principal amount								$ 75,000,000
Stated interest rate								3.92%
Mortgages | Texas-New Mexico Power Company | First Mortgage Bonds 4.06 Percent Due 2044
Debt Instrument [Line Items]
Aggregate principal amount								$ 75,000,000
Stated interest rate								4.06%
Mortgages | Texas-New Mexico Power Company | TNMP 2019 Bond Purchase Agreement
Debt Instrument [Line Items]
Aggregate principal amount				$ 305,000,000				$ 225,000,000	$ 305,000,000.0
Stated interest rate									400.00%
Debt-to-capital ratio		65.00%
Mortgages | Texas-New Mexico Power Company | TNMP Term Loan Agreement
Debt Instrument [Line Items]
Stated interest rate											3.20%
Mortgages | Texas-New Mexico Power Company | PNMR Development Term Loan
Debt Instrument [Line Items]
Stated interest rate				3.30%
Term loan agreement with banks | PNM | PNM 2019 Term Loan | JPMorgan Chase Bank, N.A. and U.S. Bank National Association
Debt Instrument [Line Items]
Aggregate principal amount												$ 250,000,000
Term loan agreement with banks | Texas-New Mexico Power Company | TNMP Term Loan Agreement | JPMorgan Chase Bank, N.A. and U.S. Bank National Association
Debt Instrument [Line Items]
Aggregate principal amount												$ 35,000,000
Term loan agreement with banks | Texas-New Mexico Power Company | PNMR Development Term Loan | JPMorgan Chase Bank, N.A. and U.S. Bank National Association
Debt Instrument [Line Items]
Aggregate principal amount				$ 90,000,000.0
Subsequent event | Texas-New Mexico Power Company | First Mortgage Bonds 3.60 Percent Due 2029
Debt Instrument [Line Items]
Aggregate principal amount							$ 80,000,000
Subsequent event | Mortgages | Texas-New Mexico Power Company | First Mortgage Bonds 3.60 Percent Due 2029
Debt Instrument [Line Items]
Aggregate principal amount							$ 80,000,000
Stated interest rate							3.60%
Deposit Related To Potential Transmission Interconnections | PNMR Development
Debt Instrument [Line Items]
Amount of related party transaction			$ 68,200,000
Interest charges				900,000
Other deferred credits				$ 68,200,000

XML

Financing - Short-term Debt and Liquidity (Details)			3 Months Ended	12 Months Ended
	Apr. 01, 2019 USD ($)	Jan. 18, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) derivative	Jul. 01, 2019 USD ($)	May 03, 2019 USD ($)	Mar. 29, 2019 USD ($)	Feb. 26, 2019 USD ($)	Feb. 22, 2019 USD ($)	Feb. 21, 2019 USD ($)
Short-term Debt [Line Items]
Financing capacity										$ 25,000,000.0	$ 24,500,000.0
Short-term debt			$ 223,800,000	$ 235,900,000
Letters of credit outstanding			4,700,000
Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity							$ 732,500,000
PNMR | Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity							239,400,000
Consolidated invested cash							900,000
PNMR 2018 One-Year Term Loan
Short-term Debt [Line Items]
Short-term debt			$ 150,000,000	150,000,000
Term of loan			1 year
PNMR 2018 One-Year Term Loan | PNMR
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt			3.24%
PNMR Development Revolving Credit Facility
Short-term Debt [Line Items]
Short-term debt			$ 11,600,000	6,000,000
Variable Rate Short-Term Debt
Short-term Debt [Line Items]
Term of derivatives					4 years
Debt issued					$ 50,000,000.0
PNMR Revolving Credit Facility
Short-term Debt [Line Items]
Financing capacity			$ 10,000,000.0
PNMR Revolving Credit Facility | PNMR
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt			3.74%
PNMR Development Revolving Credit Facility | PNMR
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt			3.49%
PNM
Short-term Debt [Line Items]
Short-term debt			$ 0	42,400,000
Letters of credit outstanding			2,500,000
Short-term debt – affiliate			0	19,800,000
PNM | Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity							397,500,000
Consolidated invested cash							9,000,000
PNM | Lines of credit
Short-term Debt [Line Items]
NMPRC approved credit facility			40,000,000
Short-term debt			0	10,000,000
PNM | Lines of credit | Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity							40,000,000
PNM | PNM Revolving Credit Facility
Short-term Debt [Line Items]
Financing capacity			40,000,000.0
TNMP
Short-term Debt [Line Items]
Short-term debt			0	17,500,000
Letters of credit outstanding			700,000
Short-term debt – affiliate			0	100,000
TNMP | Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity							45,700,000
Consolidated invested cash							0
TNMP | TNMP 2019 Bond Purchase Agreement
Short-term Debt [Line Items]
Debt issued								$ 225,000,000	$ 305,000,000.0
TNMP | First mortgage bonds
Short-term Debt [Line Items]
Extinguishment of debt		$ 172,300,000
Stated interest rate		9.50%
TNMP | PNMR 2018 One-Year Term Loan
Short-term Debt [Line Items]
Debt issued								150,000,000
TNMP | First Mortgage Bonds 3.60 Percent Due 2029 | Subsequent event
Short-term Debt [Line Items]
Debt issued						$ 80,000,000
PNMR Development
Short-term Debt [Line Items]
Short-term debt – affiliate			3,100,000	0
PNMR Development | Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity							$ 9,900,000
Revolving credit facility
Short-term Debt [Line Items]
Financing capacity			300,000,000.0
Short-term debt			62,200,000	20,000,000
Revolving credit facility | PNM
Short-term Debt [Line Items]
Financing capacity			400,000,000.0
Short-term debt			0	32,400,000
Revolving credit facility | TNMP
Short-term Debt [Line Items]
Financing capacity			75,000,000.0
Short-term debt			0	17,500,000
Revolving credit facility | TNMP | First mortgage bonds
Short-term Debt [Line Items]
Collateral amount			75,000,000
Interest rate contract
Short-term Debt [Line Items]
Number of derivatives | derivative					3
Interest rate 1 | Variable Rate Short-Term Debt
Short-term Debt [Line Items]
Fixed interest rate					1.926%
Interest rate 2 | Variable Rate Short-Term Debt
Short-term Debt [Line Items]
Fixed interest rate					1.823%
Interest rate 3 | Variable Rate Short-Term Debt
Short-term Debt [Line Items]
Fixed interest rate					1.629%
Interest rate 3 | Level 2 | Cash Flow Hedge
Short-term Debt [Line Items]
Fair value gain (loss)			1,400,000
Fair value gain (loss)				$ 1,000,000
Mortgages | TNMP | TNMP 2019 Bond Purchase Agreement
Short-term Debt [Line Items]
Debt issued			$ 305,000,000					$ 225,000,000	$ 305,000,000.0
Stated interest rate									400.00%
Mortgages | TNMP | First Mortgage Bonds 3.60 Percent Due 2029 | Subsequent event
Short-term Debt [Line Items]
Debt issued						$ 80,000,000
Stated interest rate						3.60%
Unsecured Debt | TNMP | First mortgage bonds
Short-term Debt [Line Items]
Extinguishment of debt	$ 172,300,000
Stated interest rate	9.50%

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Pension and Other Postretirement Benefit Plans (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
PNM | Pension Plan
Components of Net Periodic Benefit Cost
Service cost	$ 0	$ 0
Interest cost	6,294,000	6,068,000
Expected return on plan assets	(8,527,000)	(8,672,000)
Amortization of net (gain) loss	3,880,000	4,087,000
Amortization of prior service cost	(241,000)	(241,000)
Net Periodic Benefit Cost	1,406,000	1,242,000
Contributions by employer	0	0
Expected employer contributions for future fiscal years	0
Expected employer contributions in year 5	1,300,000
Expected employer contributions in year 6	$ 22,900,000
PNM | Pension Plan | Minimum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate	4.20%
PNM | Pension Plan | Maximum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate	4.60%
PNM | OPEB Plan
Components of Net Periodic Benefit Cost
Service cost	$ 13,000	21,000
Interest cost	829,000	860,000
Expected return on plan assets	(1,318,000)	(1,353,000)
Amortization of net (gain) loss	169,000	588,000
Amortization of prior service cost	(99,000)	(416,000)
Net Periodic Benefit Cost	(406,000)	(300,000)
Contributions by employer	0	0
PNM | Executive Retirement Program
Components of Net Periodic Benefit Cost
Service cost	0	0
Interest cost	162,000	155,000
Expected return on plan assets	0	0
Amortization of net (gain) loss	79,000	90,000
Amortization of prior service cost	0	0
Net Periodic Benefit Cost	241,000	245,000
Contributions by employer	400,000	500,000
Total expected employer contributions for fiscal year	1,500,000
Estimated employer contributions in Year 2-5	5,600,000
TNMP | Pension Plan
Components of Net Periodic Benefit Cost
Service cost	0	0
Interest cost	672,000	656,000
Expected return on plan assets	(967,000)	(991,000)
Amortization of net (gain) loss	235,000	272,000
Amortization of prior service cost	0	0
Net Periodic Benefit Cost	(60,000)	(63,000)
Contributions by employer	0	0
Estimated employer contributions in Year 2-5	$ 0
TNMP | Pension Plan | Minimum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate	4.20%
TNMP | Pension Plan | Maximum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate	4.60%
TNMP | OPEB Plan
Components of Net Periodic Benefit Cost
Service cost	$ 13,000	33,000
Interest cost	113,000	119,000
Expected return on plan assets	(129,000)	(135,000)
Amortization of net (gain) loss	(110,000)	(56,000)
Amortization of prior service cost	0	0
Net Periodic Benefit Cost	(113,000)	(39,000)
Contributions by employer	0	300,000
TNMP | Executive Retirement Program
Components of Net Periodic Benefit Cost
Service cost	0	0
Interest cost	8,000	7,000
Expected return on plan assets	0	0
Amortization of net (gain) loss	4,000	4,000
Amortization of prior service cost	0	0
Net Periodic Benefit Cost	12,000	11,000
Total expected employer contributions for fiscal year	100,000
Estimated employer contributions in Year 2-5	300,000
TNMP | Executive Retirement Program | Maximum
Components of Net Periodic Benefit Cost
Contributions by employer	$ 100,000	$ 100,000

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Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - PNM - Nuclear spent fuel and waste disposal - Palo Verde Nuclear Generating Station - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss	$ 57.7
Other deferred credits
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual	$ 12.5	$ 12.4

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Commitments and Contingencies - The Clean Air Act (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($) option T	Feb. 25, 2019 parts_per_billion	Dec. 31, 2018 USD ($) MW	Feb. 09, 2016 state	Oct. 01, 2015 parts_per_billion	Sep. 30, 2015 parts_per_billion	May 14, 2015 lb / MMBTU	Apr. 30, 2013 well	Feb. 28, 2013 claim state mine	Dec. 31, 1999 state
Public Utilities, Commitments And Contingencies [Line Items]
Number of options for meeting BTA standards | option	7
Expected number of additional monitoring wells	38
Clean Air Act related to regional haze
Public Utilities, Commitments And Contingencies [Line Items]
Number of states to address regional haze (in states) | state										50
Potential to emit tons per year of visibility impairing pollution (in tons, more than) | T	250
Clean Power Plan
Public Utilities, Commitments And Contingencies [Line Items]
Number of states that filed a petition against the Clean Power Plan | state				29
PNM | WEG v OSM lawsuit
Public Utilities, Commitments And Contingencies [Line Items]
Number of mines impacted | mine									7
Number of states impacted | state									4
Number of claims for relief, filed | claim									15
PNM | Santa Fe generating station
Public Utilities, Commitments And Contingencies [Line Items]
Number of wells with elevated levels of nitrates | well								3
PNM | San Juan Generating Station Unit 4 | Clean Air Act, SNCR
Public Utilities, Commitments And Contingencies [Line Items]
Pre-tax impairment of investments			$ 35.0
Undepreciated investment in ownership to be obtained			11.9
Forecasted undepreciated investment			$ 23.1
Remaining undepreciated investment	$ 371.6
PNM | San Juan Generating Station | Clean Air Act, SNCR
Public Utilities, Commitments And Contingencies [Line Items]
Additional ownership to be obtained (in megawatts) | MW			132
PNM | San Juan Generating Station | WEG v OSM lawsuit
Public Utilities, Commitments And Contingencies [Line Items]
Number of claims for relief, filed | claim									2
PNMR Development | San Juan Generating Station Unit 4 | Clean Air Act, SNCR
Public Utilities, Commitments And Contingencies [Line Items]
Potential acquisition of ownership (in megawatts) | MW			65
Maximum | PNM | San Juan Generating Station and Four Corners
Public Utilities, Commitments And Contingencies [Line Items]
Government standard emission limit (in ozone parts per million) | parts_per_billion		75			70	75
San Juan Generating Station | PNM | National Ambient Air Quality Standards
Public Utilities, Commitments And Contingencies [Line Items]
Revised SO2 emissions (in pounds per MMBTU) | lb / MMBTU							0.10

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Commitments and Contingencies - Coal Supply (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Aug. 01, 2016 payment	Jan. 31, 2016 USD ($)
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	$ 53,863,000	$ 54,808,000
PNM
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	43,650,000	43,516,000
PNM | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory assets	100,000,000
PNM | Loss on long-term purchase commitment | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual	70,400,000	70,100,000
Final reclamation, capped amount to be collected	100,000,000.0	100,000,000
PNM | Loss on long-term purchase commitment | Underground
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual	23,800,000	23,200,000
PNM | Loss on long-term purchase commitment | San Juan Generating Station | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss	102,600,000
PNM | Loss on long-term purchase commitment | San Juan Generating Station | Underground
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss	40,000,000
Coal supply | PNM | San Juan Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	26,300,000	26,300,000
Coal supply | NM Capital | San Juan Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Requirement to post reclamation bonds	118,700,000
Cash used to support bank letter or credit arrangement	30,300,000				$ 30,300,000
Increase in coal mine decommissioning liability | PNM | Underground and Surface
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowance, additional amount recorded		39,200,000
Increase in coal mine decommissioning liability | PNM | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowance, additional amount recorded		29,800,000
Increase in coal mine decommissioning liability | PNM | Underground
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowance, additional amount recorded		9,400,000
Increase in coal mine decommissioning liability | PNM | Loss on long-term purchase commitment
Public Utilities, Commitments And Contingencies [Line Items]
Estimated underpaid surface mining royalties under proposed rate change			$ 2,500,000
Mine Reclamation Trust | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Required contribution to Reclamation Trust, current fiscal year	6,500,000
Reclamation trust funding, year 2	10,200,000
Reclamation trust funding, year 3	10,900,000
San Juan Generating Station | Loss on long-term purchase commitment | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Annual funding post-term reclamation trust		10,000,000
Four Corners | Mine Reclamation Trust | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Required contribution to Reclamation Trust, current fiscal year		$ 2,300,000
Reclamation trust funding, year 2	2,300,000
Reclamation trust funding, year 3	$ 2,300,000
Number of annual installment payments | payment				13

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Commitments and Contingencies - Royalty Rates, Tax Assessment, Insurance and Other Matters (Details)		1 Months Ended		3 Months Ended
	Mar. 28, 2017	Sep. 30, 2012 landowner	Apr. 30, 2010 city	Mar. 31, 2019 USD ($) generating_unit	Dec. 01, 2015 Allotment_Parcel	Jul. 13, 2015 a	Jan. 22, 2015 Allotment_Parcel	Feb. 27, 2014 lawsuit	Aug. 31, 2013
Continuous highwall mining | San Juan Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Proposed retroactive surface mining royalty rate									12.50%
Surface mining royalty rate applied				8.00%
Estimated underpaid surface mining royalties under proposed rate change				$ 5,000,000
PNM's share estimated underpaid surface mining royalties under proposed rate change				46.30%
PNM | Navajo Nation Allottee Matters
Public Utilities, Commitments And Contingencies [Line Items]
Number of landowners involved in the appeal | landowner		43
Number of allotments where landowners are revoking rights of way renewal consents (in allotment parcels) | Allotment_Parcel					2		10
Area of land (in acres) | a						15.49
Number of allotment parcels at issue that are not to be condemned | Allotment_Parcel					2
Number of allotment parcels at issue | Allotment_Parcel					5
PNM | Palo Verde Nuclear Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Number of cities to provide cooling water | city			5
Term of agreement for cooling water			40 years
PNM | Palo Verde Nuclear Generating Station | Nuclear plant
Public Utilities, Commitments And Contingencies [Line Items]
Ownership percentage in nuclear reactor				10.20%
Number of units | generating_unit				3
Maximum potential assessment per incident				$ 41,600,000.0
Annual payment limitation related to incident				6,200,000.0
Aggregate amount of all risk insurance				2,750,000,000.00
Maximum amount under Nuclear Electric Insurance Limited				5,400,000.0
PNM | Maximum | Palo Verde Nuclear Generating Station | Nuclear plant
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage				14,100,000,000.0
Liability insurance coverage sublimit				2,250,000,000.00
Commercial providers | PNM | Palo Verde Nuclear Generating Station | Nuclear plant
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage				450,000,000
Industry Wide Retrospective Assessment Program | PNM | Palo Verde Nuclear Generating Station | Nuclear plant
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage				$ 13,600,000,000.0
Pending litigation
Public Utilities, Commitments And Contingencies [Line Items]
Number of pending claims | lawsuit								2
Written notification to terminate agreement, minimum period of time required	30 days
Settled litigation
Public Utilities, Commitments And Contingencies [Line Items]
Number of pending claims | lawsuit								1

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Regulatory and Rate Matters - PNM (Details) $ in Thousands															1 Months Ended	3 Months Ended			12 Months Ended	30 Months Ended
	Aug. 24, 2018 Facility power_purchase_agreement MW	Jun. 30, 2018 USD ($)	Jan. 31, 2018	Jan. 10, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jul. 03, 2017	May 23, 2017 USD ($)	Dec. 07, 2016 USD ($)	Sep. 28, 2016 USD ($) MW	Aug. 04, 2016 USD ($) MW	May 04, 2016	Jan. 16, 2016 lease	Aug. 27, 2015 USD ($)	Jan. 15, 2015	Sep. 30, 2016 USD ($)	Mar. 31, 2019 USD ($) lease MW	Mar. 31, 2018 USD ($)	Dec. 31, 2017	Dec. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	Mar. 22, 2019	Aug. 22, 2018 USD ($)	Jun. 20, 2018 MW	Mar. 21, 2018 MW	Oct. 31, 2017 USD ($)	Oct. 17, 2017 MW	Sep. 05, 2017 MW	Jun. 01, 2017 GWh MW	Oct. 26, 2016 MW	Jul. 01, 2016 USD ($)	Jan. 31, 2016 lease MW	Jan. 15, 2016 USD ($) lease MW
Public Utilities, Commitments And Contingencies [Line Items]
Pre-tax regulatory disallowance																				$ 58,000
Regulatory disallowances and restructuring costs																$ 1,345	$ 0
Percent of non-fuel revenue requirement change implemented			50.00%
Ownership percentage																50.00%
Excess return on jurisdictional equity that would require refund																0.50%
PNM
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs																$ 1,345	0
Planning period covered of IRP						20 years
Action plan, covered period						4 years
PNMR Development
Public Utilities, Commitments And Contingencies [Line Items]
Solar generation capacity (in megawatts) | MW																30											50
Ownership percentage																50.00%
Construction of solar generation capacity (in megawatts) | MW																10
2015 Electric Rate Case | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Requested rate increase (decrease)													$ 123,500
Requested rate increase (decrease) of non-fuel revenue										$ 121,500			$ 121,700			$ 121,500
Requested return on equity													10.50%
Requested rate increase (decrease) for fuel related costs																42,900
Requested rate increase (decrease) for non-fuel related revenues																200
Hearing examiner's recommended rate increase (decrease) of non-fuel revenue										$ 41,300
Hearing examiner's recommended return on equity										9.575%
Approved rate increase (decrease)									$ 61,200
Estimated period of time for supreme court appeal decision															15 months
Estimate of possible loss																$ 144,700
Renewable Portfolio Standard | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Number of megawatts of Solar PV facilities | MW																157
Current output in the geothermal facility (in megawatts) | MW																15
Solar generation capacity (in megawatts) | MW																106.8
Requested approval to procure a new solar facilities to be constructed (in megawatts) | MW																50
Renewable Energy Rider | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Recorded revenues from renewable rider																$ 12,700	$ 10,900
Integrated Resource Plan, 2011 | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Frequency of IRP filings																3 years
Planning period covered of IRP																20 years
Energy Imbalance Market | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Initial capital investments to be recovered																						$ 20,900
Other expenses to be recovered																						$ 7,400
Facebook Data Center
Public Utilities, Commitments And Contingencies [Line Items]
Number of additional PPAs | power_purchase_agreement	2
Power purchase agreement term																		25 years
Facebook Data Center | Casa Mesa Wind
Public Utilities, Commitments And Contingencies [Line Items]
Solar generation capacity (in megawatts) | MW																								50
Facebook Data Center | Avangrid Renewables, LLC
Public Utilities, Commitments And Contingencies [Line Items]
Solar generation capacity (in megawatts) | MW																								166
Facebook Data Center | Route 66 Solar Energy Center
Public Utilities, Commitments And Contingencies [Line Items]
Solar generation capacity (in megawatts) | MW	100																							50
Number of solar facilities | Facility	2
Palo Verde Nuclear Generating Station, Unit 2 Leases | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Number of megawatts purchased (in megawatts) | MW																64.1															64.1	64.1
Number of leases under which assets were purchased | lease												3				3															3	3
Estimated annual property tax expense																																$ 800
Number of leases under which lease term was extended | lease												1
Lease term extension period												8 years
Number of megawatts nuclear generation (in megawatts) | MW									114.6	114.6																			114.6
Net book value																$ 72,600
Net book value of capitalized improvements																37,600
Palo Verde Nuclear Generating Station, Unit 2 Leases | 2015 Electric Rate Case | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Hearing examiner's proposed disallowance of recovery										$ 163,300
Initial rate base value									$ 83,700
Disallowance of the recovery undepreciated costs of capitalized leasehold improvements									$ 43,800
Period of time for which capital improvements were disallowed															15 months
Pre-tax regulatory disallowance		$ 4,000			$ 3,100										$ 6,800	1,300
Period of time to issue a decision and take action on remanded issues					7 months
Alvarado square | 2015 Electric Rate Case | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Hearing examiner's recommended amount to not be recovered from retail customers										4,500
Pre-tax regulatory disallowance of costs recorded as regulatory assets and deferred charges															$ 4,500
Palo Verde Nuclear Generating Station, Unit 1 Leases, extended | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Estimated annual property tax expense																																$ 1,500
Estimated annual rent expense										18,100
Number of leases under which lease term was extended | lease																																4
Lease term extension period														8 years
Clean Air Act, Balanced Draft Technology | San Juan Generating Station Units 1 and 4 | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Net book value																$ 49,700
Clean Air Act, Balanced Draft Technology | San Juan Generating Station Units 1 and 4 | 2015 Electric Rate Case | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Requested base rate increase (decrease)										40,000
Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other Costs | Clean Air Act, Balanced Draft Technology | San Juan Generating Station Units 1 and 4 | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Installation capital costs										$ 52,300
NMPRC
Public Utilities, Commitments And Contingencies [Line Items]
Requested rate increase (decrease)								$ 99,200
Requested return on equity								10.125%
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate							21 years
Action plan, covered period																4 years
NMPRC | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Requested rate increase (decrease)							$ 10,300
Requested return on equity							9.575%
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate							3 years
Requested approval to procure additional gigawatt hours in year 1 | GWh																												80
Requested approval to procure a new solar facilities to be constructed (in megawatts) | MW																							50			50		50
Proposed revision to rider that will allow for recovery																			$ 49,600
Notice of proposed dismissal, period to show good cause											30 days
Required Percentage by 2011 | Renewable Portfolio Standard | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Required percentage of renewable energy in portfolio to electric sales																10.00%
Required Percentage by 2015 | Renewable Portfolio Standard | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Required percentage of renewable energy in portfolio to electric sales																15.00%
Required Percentage by 2020 | Renewable Portfolio Standard | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Required percentage of renewable energy in portfolio to electric sales																20.00%
Required Percentage by 2020 | Energy Transition Act | Electric-Generation Portfolio Standard
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage																					0.20
Required Percentage by 2025 | Energy Transition Act | Electric-Generation Portfolio Standard
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage																					0.40
Required Percentage by 2030 | Energy Transition Act | Electric-Generation Portfolio Standard
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage																					0.50
Required Percentage by 2040 | Energy Transition Act | Electric-Generation Portfolio Standard
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage																					0.80
Required Percentage by 2045 | Energy Transition Act | Electric-Generation Portfolio Standard
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage																					1.00
Maximum | Renewable Portfolio Standard | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Reasonable cost threshold																3.00%
New Mexico Wind | Renewable Portfolio Standard 2014 | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Number of megawatts for wind energy | MW																204
New Mexico Wind | NMPRC | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Requested approval to procure additional gigawatt hours in year 2 | GWh																												105
Red Mesa Wind | Renewable Portfolio Standard 2014 | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Number of megawatts for wind energy | MW																102
Lightning Dock Geothermal | NMPRC | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Requested approval to procure additional gigawatt hours in year 1 | GWh																												55
Requested approval to procure additional gigawatt hours in year 2 | GWh																												77
Four Corners
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs				$ 47,600
Regulatory disallowance																									$ 90,100					$ 148,100

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Regulatory and Rate Matters - Application For a New 345 KV Transmission Line (Details) $ in Millions	Aug. 10, 2018 USD ($) kv MW	Mar. 21, 2018 MW
KV Transmission Line
Public Utilities, General Disclosures [Line Items]
Transmission line and associated facilities generation capacity (in kilovolts) | kv	345
Solar generation capacity (in megawatts) | MW	166
Estimated cost of project | $	$ 85.0
Facebook Data Center
Public Utilities, General Disclosures [Line Items]
Estimated cost of project | $	$ 39.0
Estimated cost of project, percentage	46.00%
Facebook Data Center | Avangrid Renewables, LLC
Public Utilities, General Disclosures [Line Items]
Solar generation capacity (in megawatts) | MW		166

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Regulatory and Rate Matters - TNMP Narrative (Details) - USD ($) $ in Millions			3 Months Ended	12 Months Ended
	Nov. 02, 2018	May 30, 2018	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Mar. 31, 2019	Aug. 06, 2018
Public Utilities, Commitments And Contingencies [Line Items]
Unrecovered investment revenue		$ 20.2
TNMP
Public Utilities, Commitments And Contingencies [Line Items]
Net regulatory liability					$ 37.8
Reduction to revenue			$ 1.5	$ 5.4
Energy efficiency cost recovery, requested change amount		5.7					$ 5.6
Energy efficiency cost recovery, requested bonus		0.9				$ 0.8	$ 0.8
TNMP | 2018 TNMP Rate Case
Public Utilities, Commitments And Contingencies [Line Items]
Requested rate increase (decrease)	$ 10.0	$ 25.9
Requested return on equity	9.65%	10.50%
Requested cost of debt	6.44%	7.20%
Requested debt capital structure	55.00%	50.00%
Requested equity capital structure	45.00%	50.00%
Investments excluded from rate request	$ 10.6
Refund of federal income tax rates period					5 years

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Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - TNMP - USD ($) $ in Millions	Mar. 21, 2019	Mar. 27, 2018	Sep. 13, 2017	Mar. 14, 2017	Sep. 08, 2016
Transmission Cost of Service Rates
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base				$ 30.2	$ 9.5
Annual Increase in Revenue				$ 4.8	$ 1.8
PUCT
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease)	$ 111.8	$ 32.0	$ 27.5
Proposed increase (decrease) in revenues	$ 14.3	$ 0.6	$ 4.7

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Lease Commitments - Narrative (Details) $ in Millions		1 Months Ended	3 Months Ended
	Jan. 15, 2016 USD ($) lease MW	Apr. 30, 2018 USD ($)	Mar. 31, 2019 USD ($) lease	Dec. 31, 2018 USD ($)	Jan. 31, 2016 lease	Jan. 16, 2016 lease	Jan. 15, 2015 lease
Operating Leased Assets [Line Items]
Capitalized operating lease costs			$ 1.1
Capitalized financing lease costs (less than)			0.1
Lessee, operating lease, unguaranteed residual value			22.1
Operating lease, unguaranteed residual value				$ 18.5
PNM
Operating Leased Assets [Line Items]
Capitalized operating lease costs			0.4
Capitalized financing lease costs (less than)			0.1
Lessee, operating lease, unguaranteed residual value			9.9
Operating lease, unguaranteed residual value				$ 7.5
PNM | Navajo Nation
Operating Leased Assets [Line Items]
Annual lease payments			6.0
Right-of-way lease payments		$ 6.9
PNM | Palo Verde Nuclear Generating Station, Unit 1 Leases
Operating Leased Assets [Line Items]
Number of leases, expiring | lease							4
Number of leases under which lease term was extended | lease							4
Annual lease payments during renewal period			16.5
PNM | Palo Verde Nuclear Generating Station, Unit 2 Leases
Operating Leased Assets [Line Items]
Number of leases, expiring | lease						4
Number of leases under which lease term was extended | lease						1
Annual lease payments during renewal period			$ 1.6
Number of leases under which assets were purchased | lease	3		3		3	3
Leased capacity to be purchased (in megawatts) | MW	32.76
PNM | Palo Verde Nuclear Generating Station, Unit 2 Leases, 31.25 MW
Operating Leased Assets [Line Items]
Number of leases under which assets were purchased | lease	1
Payment to lessors	$ 78.1
PNM | Palo Verde Nuclear Generating Station, Unit 2 Leases, January 15, 2016
Operating Leased Assets [Line Items]
Leased capacity to be purchased (in megawatts) | MW	31.25
PNM | Palo Verde Nuclear Generating Station, Unit 2 Leases, 32.76 MW
Operating Leased Assets [Line Items]
Number of leases under which assets were purchased | lease	2
Payment to lessors	$ 85.2
PNM | Palo Verde Nuclear Generating Station
Operating Leased Assets [Line Items]
Restriction on conveying, transferring, leasing and dividends				5.00%
Loss contingency, lease arrangements (up to)			$ 161.2
TNMP
Operating Leased Assets [Line Items]
Capitalized operating lease costs			0.7
Capitalized financing lease costs (less than)			0.1
Lessee, operating lease, unguaranteed residual value			12.2
Operating lease, unguaranteed residual value				$ 11.0
Equipment
Operating Leased Assets [Line Items]
Operating lease, residual value of leased asset			1.6
Equipment | PNM
Operating Leased Assets [Line Items]
Operating lease, residual value of leased asset			0.5
Equipment | TNMP
Operating Leased Assets [Line Items]
Operating lease, residual value of leased asset			$ 1.1

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Lease Commitments - Operating Lease Balance Sheet Information (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019
Operating leases:
Operating lease assets, net of amortization	$ 150,426	$ 157,440
Current portion of operating lease liabilities	26,197	25,189
Long-term portion of operating lease liabilities	124,937	135,174
PNM
Operating leases:
Operating lease assets, net of amortization	137,756	143,816
Current portion of operating lease liabilities	22,762	21,589
Long-term portion of operating lease liabilities	115,436	124,891
TNMP
Operating leases:
Operating lease assets, net of amortization	12,160	12,942
Current portion of operating lease liabilities	3,023	3,132
Long-term portion of operating lease liabilities	$ 9,088	$ 9,787

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Lease Commitments - Finance Lease Balance Sheet Information (Details) $ in Thousands	Mar. 31, 2019 USD ($)
Financing leases:
Non-utility property	$ 2,904
Accumulated depreciation	(78)
Non-utility property, net	2,826
Other current liabilities	450
Other deferred credits	2,089
PNM
Financing leases:
Non-utility property	1,635
Accumulated depreciation	(37)
Non-utility property, net	1,598
Other current liabilities	233
Other deferred credits	1,083
TNMP
Financing leases:
Non-utility property	1,268
Accumulated depreciation	(40)
Non-utility property, net	1,228
Other current liabilities	217
Other deferred credits	$ 1,006

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Lease Commitments - Schedule of Weighted Average Remaining Lease Terms and Discount Rates (Details)	Mar. 31, 2019
Weighted average remaining lease term (In years):
Operating leases	6 years 11 months 12 days
Financing leases	5 years 8 months 26 days
Weighted average discount rate:
Operating leases	3.88%
Financing leases	4.43%
PNM
Weighted average remaining lease term (In years):
Operating leases	7 years 2 months 5 days
Financing leases	5 years 8 months 19 days
Weighted average discount rate:
Operating leases	3.88%
Financing leases	4.34%
TNMP
Weighted average remaining lease term (In years):
Operating leases	4 years 8 months 1 day
Financing leases	5 years 9 months
Weighted average discount rate:
Operating leases	3.88%
Financing leases	4.55%

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Lease Commitments - Components of Lease Expense (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Lease, Cost [Line Items]
Total operating lease expense	$ 7,611
Financing lease expense:
Amortization of right-of-use assets	125
Interest on lease liabilities	32
Total financing lease expense	157
Variable lease expense	0
Short-term lease expense	94
Total lease expense for the period	7,862
PNM
Lease, Cost [Line Items]
Total operating lease expense	7,231
Financing lease expense:
Amortization of right-of-use assets	66
Interest on lease liabilities	16
Total financing lease expense	82
Variable lease expense	0
Short-term lease expense	74
Total lease expense for the period	7,387
TNMP
Lease, Cost [Line Items]
Total operating lease expense	241
Financing lease expense:
Amortization of right-of-use assets	58
Interest on lease liabilities	17
Total financing lease expense	75
Variable lease expense	0
Short-term lease expense	3
Total lease expense for the period	$ 319

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Lease Commitments - Schedule of Supplemental Cash Flows Related to Leases (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 9,891
Operating cash flows from financing leases	32
Finance cash flows from financing leases	58
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	157,440
Financing leases	2,904
PNM
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	9,452
Operating cash flows from financing leases	16
Finance cash flows from financing leases	25
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	143,816
Financing leases	1,635
TNMP
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	284
Operating cash flows from financing leases	17
Finance cash flows from financing leases	33
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	12,942
Financing leases	$ 1,268

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Lease Commitments - Schedule of Future Expected Lease Payments (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Financing
Remainder of 2019	$ 475
2020	613
2021	591
2022	568
2023	488
Later years	438
Total minimum lease payments	3,173
Less: Imputed interest	634
Lease liabilities as of March 31, 2019	2,539
Operating
Remainder of 2019	20,980
2020	30,555
2021	29,158
2022	28,255
2023	18,879
Later years	43,490
Total minimum lease payments	171,317
Less: Imputed interest	20,183
Lease liabilities as of March 31, 2019	151,134
Operating leases
Remainder of 2019		$ 31,772
2020		30,404
2021		29,012
2022		28,175
2023		18,868
Later years		43,489
Total minimum lease payments		181,720
PNM
Financing
Remainder of 2019	266
2020	344
2021	332
2022	319
2023	307
Later years	224
Total minimum lease payments	1,792
Less: Imputed interest	476
Lease liabilities as of March 31, 2019	1,316
Operating
Remainder of 2019	17,917
2020	27,045
2021	26,505
2022	26,235
2023	17,457
Later years	42,328
Total minimum lease payments	157,487
Less: Imputed interest	19,289
Lease liabilities as of March 31, 2019	138,198
Operating leases
Remainder of 2019		27,691
2020		27,000
2021		26,462
2022		26,217
2023		17,447
Later years		42,329
Total minimum lease payments		167,146
TNMP
Financing
Remainder of 2019	209
2020	269
2021	259
2022	249
2023	181
Later years	214
Total minimum lease payments	1,381
Less: Imputed interest	158
Lease liabilities as of March 31, 2019	1,223
Operating
Remainder of 2019	2,622
2020	2,993
2021	2,398
2022	1,846
2023	1,281
Later years	1,151
Total minimum lease payments	12,291
Less: Imputed interest	180
Lease liabilities as of March 31, 2019	$ 12,111
Operating leases
Remainder of 2019		3,664
2020		3,102
2021		2,324
2022		1,795
2023		1,279
Later years		1,150
Total minimum lease payments		$ 13,314

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Income Taxes (Details) - USD ($) $ in Millions		3 Months Ended
	May 23, 2017	Mar. 31, 2019
Income Tax Contingency [Line Items]
Effective tax rate		9.42%
Tax benefits related to stock awards		$ 0.7
TNMP
Income Tax Contingency [Line Items]
Increase (decrease) in regulatory liability		$ 1.5
Effective tax rate		8.41%
Tax benefits related to stock awards		$ 0.2
PNM
Income Tax Contingency [Line Items]
Effective tax rate		11.89%
Tax benefits related to stock awards		$ 0.5
NMPRC
Income Tax Contingency [Line Items]
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate	21 years
NMPRC | PNM
Income Tax Contingency [Line Items]
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate	3 years

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Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Related Party Transaction [Line Items]
Ownership percentage	50.00%
Services billings: | PNMR to PNM
Related Party Transaction [Line Items]
Amount of related party transaction	$ 26,826	$ 23,679
Services billings: | PNMR to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	10,058	8,365
Services billings: | PNM to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	75	86
Services billings: | TNMP to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	35	35
Services billings: | PNMR to NMRD
Related Party Transaction [Line Items]
Amount of related party transaction	41	78
Renewable energy purchases: | PNM from NMRD
Related Party Transaction [Line Items]
Amount of related party transaction	625	370
Interconnection billings: | PNM from NMRD
Related Party Transaction [Line Items]
Amount of related party transaction	0	0
Interconnection billings: | PNM to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	0	0
Interest billings: | PNMR to PNM
Related Party Transaction [Line Items]
Amount of related party transaction	933	62
Interest billings: | PNMR to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	32	8
Interest billings: | PNM to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	72	66
Income tax sharing payments: | PNMR to PNM
Related Party Transaction [Line Items]
Amount of related party transaction	0	0
Income tax sharing payments: | TNMP to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	$ 0	$ 0

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Label	Element	Value
Common Stock [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	$ 1,157,665,000
Common Stock [Member] | Public Service Company of New Mexico [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	1,264,918,000
Noncontrolling Interest [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	66,195,000
Noncontrolling Interest [Member] | Public Service Company of New Mexico [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	66,195,000
Retained Earnings [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	644,736,000
Retained Earnings [Member] | Public Service Company of New Mexico [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	265,557,000
Parent [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	1,695,253,000
Parent [Member] | Public Service Company of New Mexico [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	$ 1,422,174,000