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, 2017

Commission File	Name of Registrants, State of Incorporation,	I.R.S. Employer
Number	Address and Telephone Number	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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

Indicate by check mark 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 (Do not check if a smaller reporting company)		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

As of April 24, 2017, 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 outstanding as of April 24, 2017 was 39,117,799 all held by PNMR (and none held by non-affiliates).

The total number of shares of common stock of TNMP outstanding as of April 24, 2017 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	76
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	110
ITEM 4. CONTROLS AND PROCEDURES	113
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	114
ITEM 1A. RISK FACTORS	114
ITEM 6. EXHIBITS	115
SIGNATURE	117

3

GLOSSARY

Definitions:
2014 IRP	PNM’s 2014 IRP
2017 IRP	PNM’s 2017 IRP
ABCWUA	Albuquerque Bernalillo County Water Utility Authority
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
BACT	Best Available Control Technology
BART	Best Available Retrofit Technology
BDT	Balanced Draft Technology
BHP	BHP Billiton, Ltd
Board	Board of Directors of PNMR
BTMU	The Bank of Tokyo-Mitsubishi UFJ, Ltd.
BTMU Term Loan Agreement	NM Capital’s $125.0 Million Unsecured Term Loan
BTU	British Thermal Unit
CAA	Clean Air Act
CCB	Coal Combustion Byproducts
CCN	Certificate of Convenience and Necessity
CIAC	Contributions in Aid of Construction
CO2	Carbon Dioxide
CSA	Coal Supply Agreement
CTC	Competition Transition Charge
DC Circuit	United States Court of Appeals for the District of Columbia Circuit
DOE	United States Department of Energy
DOI	United States Department of Interior
EGU	Electric Generating Unit
EIS	Environmental Impact Study
EPA	United States Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
ESA	Endangered Species Act
Exchange Act	Securities Exchange Act of 1934
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIP	Federal Implementation Plan
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

4

IRP	Integrated Resource Plan
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
Luna	Luna Energy Facility
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MMBTU	Million BTUs
Moody’s	Moody’s Investor Services, Inc.
MW	Megawatt
MWh	Megawatt Hour
NAAQS	National Ambient Air Quality Standards
Navajo Acts	Navajo Nation Air Pollution Prevention and Control Act, Navajo Nation Safe Drinking Water Act, and Navajo Nation Pesticide Act
NDT	Nuclear Decommissioning Trusts for PVNGS
NEC	Navopache Electric Cooperative, Inc.
NEE	New Energy Economy
NEPA	National Environmental Policy Act
NERC	North American Electric Reliability Corporation
New Mexico Wind	New Mexico Wind Energy Center
NM 2015 Rate Case	Request for a General Increase in Electric Rates Filed by PNM on August 27, 2015
NM 2016 Rate case	Request for a General Increase in Electric Rates Filed by PNM on December 7, 2016
NM Capital	NM Capital Utility Corporation, an unregulated wholly-owned subsidiary of PNMR
NM Supreme Court	New Mexico Supreme Court
NMED	New Mexico Environment Department
NMIEC	New Mexico Industrial Energy Consumers Inc.
NMMMD	The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department
NMPRC	New Mexico Public Regulation Commission
NOx	Nitrogen Oxides
NOPR	Notice of Proposed Rulemaking
NPDES	National Pollutant Discharge Elimination System
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
NSR	New Source Review
NTEC	Navajo Transitional Energy Company, LLC, an entity owned by the Navajo Nation
OCI	Other Comprehensive Income
OPEB	Other Post Employment Benefits
OSM	United States Office of Surface Mining Reclamation and Enforcement
PCRBs	Pollution Control Revenue Bonds
PNM	Public Service Company of New Mexico and Subsidiaries, a wholly-owned subsidiary of PNMR
PNM 2016 Term Loan Agreement	PNM’s $175.0 Million Unsecured Term Loan

5

PNM New Mexico Credit Facility	PNM’s $50.0 Million Unsecured Revolving Credit Facility
PNM Revolving Credit Facility	PNM’s $400.0 Million Unsecured Revolving Credit Facility
PNMR	PNM Resources, Inc. and Subsidiaries
PNMR 2015 Term    Loan Agreement	PNMR’s $150.0 Million Three-Year Unsecured Term Loan
PNMR 2016 One-Year Term Loan	PNMR’s $100.0 Million One-Year Unsecured Term Loan
PNMR 2016 Two-Year Term Loan	PNMR’s $100.0 Million Two-Year Unsecured Term Loan
PNMR Development	PNMR Development and Management Company, an unregulated wholly-owned subsidiary of PNMR
PNMR Revolving Credit Facility	PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan Agreement	PNMR’s $150.0 Million One-Year Unsecured Term Loan
PPA	Power Purchase Agreement
PSA	Power Sales Agreement
PSD	Prevention of Significant Deterioration
PUCT	Public Utility Commission of Texas
PV	Photovoltaic
PVNGS	Palo Verde Nuclear Generating Station
RA	San Juan Project Restructuring Agreement
RCRA	Resource Conservation and Recovery Act
RCT	Reasonable Cost Threshold
REA	New Mexico’s Renewable Energy Act of 2004
REC	Renewable Energy Certificates
Red Mesa Wind	Red Mesa Wind Energy Center
REP	Retail Electricity Provider
Rio Bravo	Rio Bravo Generating Station
RMC	Risk Management Committee
ROE	Return on Equity
RPS	Renewable Energy Portfolio Standard
S&P	Standard and Poor’s Ratings Services
SCR	Selective Catalytic Reduction
SEC	United States Securities and Exchange Commission
SIP	State Implementation Plan
SJCC	San Juan Coal Company
SJGS	San Juan Generating Station
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
TCEQ	Texas Commission on Environmental Quality
TECA	Texas Electric Choice Act
Tenth Circuit	United States Court of Appeals for the Tenth Circuit
TNMP	Texas-New Mexico Power Company and Subsidiaries, a wholly-owned subsidiary of TNP
TNMP Revolving Credit Facility	TNMP’s $75.0 Million Secured Revolving Credit Facility
TNP	TNP Enterprises, Inc. and Subsidiaries, a wholly-owned subsidiary of PNMR

6

Tri-State	Tri-State Generation and Transmission Association, Inc.
Tucson	Tucson Electric Power Company
UG-CSA	Underground Coal Sales Agreement
US Supreme Court	Supreme Court of the United States
Valencia	Valencia Energy Facility
VaR	Value at Risk
VIE	Variable Interest Entity
WEG	WildEarth Guardians
Westmoreland	Westmoreland Coal Company
Westmoreland Loan	NM Capital’s $125.0 million loan to WSJ
WSJ	Westmoreland San Juan, LLC, an indirect wholly-owned subsidiary of Westmoreland

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,
	2017			2016
	(In thousands, except per share amounts)
Electric Operating Revenues	$	330,178		$	310,961
Operating Expenses:
Cost of energy	102,804			92,369
Administrative and general	47,532			47,109
Energy production costs	31,787			42,686
Regulatory disallowances and restructuring costs	—			774
Depreciation and amortization	56,383			49,829
Transmission and distribution costs	16,477			16,594
Taxes other than income taxes	19,235			20,092
Total operating expenses	274,218			269,453
Operating income	55,960			41,508
Other Income and Deductions:
Interest income	4,881			3,622
Gains on available-for-sale securities	6,661			6,218
Other income	4,902			4,264
Other (deductions)	(3,483		)	(2,999		)
Net other income and deductions	12,961			11,105
Interest Charges	31,700			31,491
Earnings before Income Taxes	37,221			21,122
Income Taxes	10,775			7,157
Net Earnings	26,446			13,965
(Earnings) Attributable to Valencia Non-controlling Interest	(3,452		)	(3,287		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)
Net Earnings Attributable to PNMR	$	22,862		$	10,546
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.29		$	0.13
Diluted	$	0.29		$	0.13
Dividends Declared per Common Share	$	0.2425		$	0.2200

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,
	2017			2016
	(In thousands)
Net Earnings	$	26,446		$	13,965
Other Comprehensive Income (Loss):
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(3,030) and $(2,130)	4,736			3,328
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,078 and $4,374	(1,685		)	(6,836		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(631) and $(537)	987			839
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $72 and $503	(113		)	(786		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(44) and $(57)	68			89
Total Other Comprehensive Income (Loss)	3,993			(3,366		)
Comprehensive Income	30,439			10,599
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,452		)	(3,287		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)
Comprehensive Income Attributable to PNMR	$	26,855		$	7,180

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,
	2017			2016
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	26,446		$	13,965
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	65,888			58,563
Deferred income tax expense	10,787			7,187
Net unrealized (gains) on commodity derivatives	(1,345		)	(1,435		)
Realized (gains) on available-for-sale securities	(6,661		)	(6,218		)
Stock based compensation expense	2,687			2,653
Regulatory disallowances and restructuring costs	—			774
Other, net	(928		)	(612		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	20,553			36,215
Materials, supplies, and fuel stock	1,836			(1,716		)
Other current assets	11,441			(18,720		)
Other assets	2,753			277
Accounts payable	(3,852		)	2,004
Accrued interest and taxes	12,542			18,276
Other current liabilities	(10,009		)	(16,583		)
Other liabilities	(534		)	(4,032		)
Net cash flows from operating activities	131,604			90,598
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(114,830		)	(278,764		)
Proceeds from sales of available-for-sale securities	266,388			124,900
Purchases of available-for-sale securities	(267,891		)	(126,101		)
Return of principal on PVNGS lessor notes	—			8,547
Investment in Westmoreland Loan	—			(122,250		)
Principal repayments on Westmoreland Loan	9,590			—
Other, net	128			150
Net cash flows from investing activities	(106,615		)	(393,518		)

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,
	2017			2016
	(In thousands)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	16,000			107,400
Long-term borrowings	—			182,500
Repayment of long-term debt	(9,444		)	—
Proceeds from stock option exercise	1,112			3,275
Awards of common stock	(11,032		)	(10,020		)
Dividends paid	(19,448		)	(17,656		)
Valencia’s transactions with its owner	(4,028		)	(3,999		)
Other, net	(388		)	(761		)
Net cash flows from financing activities	(27,228		)	260,739
Change in Cash and Cash Equivalents	(2,239		)	(42,181		)
Cash and Cash Equivalents at Beginning of Period	4,522			46,051
Cash and Cash Equivalents at End of Period	$	2,283		$	3,870
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	14,951		$	11,403
Income taxes paid (refunded), net	$	(125	)	$	—
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	10,367		$	20,149

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, 2017		December 31, 2016
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	2,283	$	4,522
Accounts receivable, net of allowance for uncollectible accounts of $1,212 and $1,209	82,234		87,012
Unbilled revenues	41,808		58,284
Other receivables	27,098		28,245
Current portion of Westmoreland Loan	29,664		38,360
Materials, supplies, and fuel stock	66,140		73,027
Regulatory assets	910		3,855
Commodity derivative instruments	4,586		5,224
Income taxes receivable	5,953		6,066
Other current assets	66,093		73,444
Total current assets	326,769		378,039
Other Property and Investments:
Long-term portion of Westmoreland Loan	55,746		56,640
Available-for-sale securities	286,099		272,977
Other investments	419		547
Non-utility property	3,404		3,404
Total other property and investments	345,668		333,568
Utility Plant:
Plant in service, held for future use, and to be abandoned	7,009,698		6,944,534
Less accumulated depreciation and amortization	2,373,542		2,334,938
	4,636,156		4,609,596
Construction work in progress	232,056		208,206
Nuclear fuel, net of accumulated amortization of $50,378 and $43,905	87,379		86,913
Net utility plant	4,955,591		4,904,715
Deferred Charges and Other Assets:
Regulatory assets	496,012		501,223
Goodwill	278,297		278,297
Other deferred charges	75,342		75,238
Total deferred charges and other assets	849,651		854,758
	$	6,477,679	$	6,471,080

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, 2017			December 31, 2016
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	303,100		$	287,100
Current installments of long-term debt	414,856			273,348
Accounts payable	67,439			86,705
Customer deposits	11,207			11,374
Accrued interest and taxes	74,299			61,871
Regulatory liabilities	8,140			3,609
Commodity derivative instruments	360			2,339
Dividends declared	19,448			19,448
Other current liabilities	63,287			59,314
Total current liabilities	962,136			805,108
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,969,304			2,119,364
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	948,177			940,650
Regulatory liabilities	453,580			455,649
Asset retirement obligations	129,730			127,519
Accrued pension liability and postretirement benefit cost	121,632			125,844
Other deferred credits	126,607			140,545
Total deferred credits and other liabilities	1,779,726			1,790,207
Total liabilities	4,711,166			4,714,679
Commitments and Contingencies (See 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)	1,156,428			1,163,661
Accumulated other comprehensive income (loss), net of income taxes	(88,458		)	(92,451		)
Retained earnings	618,670			604,742
Total PNMR common stockholders’ equity	1,686,640			1,675,952
Non-controlling interest in Valencia	68,344			68,920
Total equity	1,754,984			1,744,872
	$	6,477,679		$	6,471,080

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, 2016, as originally reported	$	1,163,661		$	(92,451	)	$	604,742		$	1,675,952		$	68,920		$	1,744,872
Cumulative effect adjustment (Note 8)	—			—			10,382			10,382			—			10,382
Balance at January 1, 2017, as adjusted	1,163,661			(92,451		)	615,124			1,686,334			68,920			1,755,254
Net earnings before subsidiary preferred stock dividends	—			—			22,994			22,994			3,452			26,446
Total other comprehensive income	—			3,993			—			3,993			—			3,993
Subsidiary preferred stock dividends	—			—			(132		)	(132		)	—			(132		)
Dividends declared on common stock	—			—			(19,316		)	(19,316		)	—			(19,316		)
Proceeds from stock option exercise	1,112			—			—			1,112			—			1,112
Awards of common stock	(11,032		)	—			—			(11,032		)	—			(11,032		)
Stock based compensation expense	2,687			—			—			2,687			—			2,687
Valencia’s transactions with its owner	—			—			—			—			(4,028		)	(4,028		)
Balance at March 31, 2017	$	1,156,428		$	(88,458	)	$	618,670		$	1,686,640		$	68,344		$	1,754,984

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,
	2017			2016
	(In thousands)
Electric Operating Revenues	$	251,558		$	235,606
Operating Expenses:
Cost of energy	81,317			72,444
Administrative and general	43,047			42,028
Energy production costs	31,787			42,686
Regulatory disallowances and restructuring costs	—			774
Depreciation and amortization	36,016			31,864
Transmission and distribution costs	9,919			10,316
Taxes other than income taxes	11,141			12,197
Total operating expenses	213,227			212,309
Operating income	38,331			23,297
Other Income and Deductions:
Interest income	2,816			1,522
Gains on available-for-sale securities	6,661			6,218
Other income	3,843			3,387
Other (deductions)	(2,821		)	(1,662		)
Net other income and deductions	10,499			9,465
Interest Charges	21,012			21,591
Earnings before Income Taxes	27,818			11,171
Income Taxes	7,708			3,610
Net Earnings	20,110			7,561
(Earnings) Attributable to Valencia Non-controlling Interest	(3,452		)	(3,287		)
Net Earnings Attributable to PNM	16,658			4,274
Preferred Stock Dividends Requirements	(132		)	(132		)
Net Earnings Available for PNM Common Stock	$	16,526		$	4,142

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,
	2017			2016
	(In thousands)
Net Earnings	$	20,110		$	7,561
Other Comprehensive Income (Loss):
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(3,030) and $(2,130)	4,736			3,328
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,078 and $4,374	(1,685		)	(6,836		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(631) and $(537)	987			839
Total Other Comprehensive Income (Loss)	4,038			(2,669		)
Comprehensive Income	24,148			4,892
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,452		)	(3,287		)
Comprehensive Income Attributable to PNM	$	20,696		$	1,605

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,
	2017			2016
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	20,110		$	7,561
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	44,691			40,225
Deferred income tax expense	7,878			3,727
Net unrealized (gains) on commodity derivatives	(1,345		)	(1,435		)
Realized (gains) on available-for-sale securities	(6,661		)	(6,218		)
Regulatory disallowances and restructuring costs	—			774
Other, net	(759		)	(611		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	17,414			33,417
Materials, supplies, and fuel stock	2,083			(5,060		)
Other current assets	12,399			(13,527		)
Other assets	4,399			3,311
Accounts payable	(2,509		)	5,130
Accrued interest and taxes	16,954			20,221
Other current liabilities	2,946			(9,335		)
Other liabilities	(1,325		)	(4,505		)
Net cash flows from operating activities	116,275			73,675
Cash Flows From Investing Activities:
Utility plant additions	(65,781		)	(238,734		)
Proceeds from sales of available-for-sale securities	266,388			124,900
Purchases of available-for-sale securities	(267,891		)	(126,101		)
Return of principal on PVNGS lessor notes	—			8,547
Other, net	128			150
Net cash flows from investing activities	(67,156		)	(231,238		)

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,
	2017			2016
	(In thousands)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	(44,800		)	118,800
Dividends paid	(132		)	(132		)
Valencia’s transactions with its owner	(4,028		)	(3,999		)
Other, net	(389		)	(53		)
Net cash flows from financing activities	(49,349		)	114,616
Change in Cash and Cash Equivalents	(230		)	(42,947		)
Cash and Cash Equivalents at Beginning of Period	324			43,138
Cash and Cash Equivalents at End of Period	$	94		$	191
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	9,330		$	8,561
Income taxes paid (refunded), net	$	—		$	—
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	3,449		$	16,747

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, 2017		December 31, 2016
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	94	$	324
Accounts receivable, net of allowance for uncollectible accounts of $1,212 and $1,209	61,279		65,003
Unbilled revenues	33,897		48,289
Other receivables	23,486		25,514
Affiliate receivables	9,247		8,886
Materials, supplies, and fuel stock	62,318		64,401
Regulatory assets	—		3,442
Commodity derivative instruments	4,586		5,224
Income taxes receivable	25,977		25,807
Other current assets	60,425		67,355
Total current assets	281,309		314,245
Other Property and Investments:
Available-for-sale securities	286,099		272,977
Other investments	188		316
Non-utility property	96		96
Total other property and investments	286,383		273,389
Utility Plant:
Plant in service, held for future use, and to be abandoned	5,383,068		5,359,211
Less accumulated depreciation and amortization	1,832,695		1,809,528
	3,550,373		3,549,683
Construction work in progress	184,129		158,122
Nuclear fuel, net of accumulated amortization of $50,378 and $43,905	87,379		86,913
Net utility plant	3,821,881		3,794,718
Deferred Charges and Other Assets:
Regulatory assets	360,363		365,413
Goodwill	51,632		51,632
Other deferred charges	68,633		68,149
Total deferred charges and other assets	480,628		485,194
	$	4,870,201	$	4,867,546

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, 2017			December 31, 2016
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	16,200		$	61,000
Current installments of long-term debt	231,936			231,880
Accounts payable	49,613			55,566
Affiliate payables	33,967			23,183
Customer deposits	11,207			11,374
Accrued interest and taxes	51,942			34,819
Regulatory liabilities	8,140			3,517
Commodity derivative instruments	360			2,339
Dividends declared	132			132
Other current liabilities	47,659			33,551
Total current liabilities	451,156			457,361
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,400,036			1,399,489
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	755,872			748,666
Regulatory liabilities	421,177			423,701
Asset retirement obligations	128,794			126,601
Accrued pension liability and postretirement benefit cost	111,196			114,427
Other deferred credits	103,661			118,980
Total deferred credits and liabilities	1,520,700			1,532,375
Total liabilities	3,371,892			3,389,225
Commitments and Contingencies (See 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	(88,390		)	(92,428		)
Retained earnings	241,908			225,382
Total PNM common stockholder’s equity	1,418,436			1,397,872
Non-controlling interest in Valencia	68,344			68,920
Total equity	1,486,780			1,466,792
	$	4,870,201		$	4,867,546

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, 2016	$	1,264,918	$	(92,428	)	$	225,382		$	1,397,872		$	68,920		$	1,466,792
Net earnings	—		—			16,658			16,658			3,452			20,110
Total other comprehensive income	—		4,038			—			4,038			—			4,038
Dividends declared on preferred stock	—		—			(132		)	(132		)	—			(132		)
Valencia’s transactions with its owner	—		—			—			—			(4,028		)	(4,028		)
Balance at March 31, 2017	$	1,264,918	$	(88,390	)	$	241,908		$	1,418,436		$	68,344		$	1,486,780

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,
	2017			2016
	(In thousands)
Electric Operating Revenues	$	78,620		$	75,355
Operating Expenses:
Cost of energy	21,487			19,925
Administrative and general	10,403			9,590
Depreciation and amortization	15,371			14,508
Transmission and distribution costs	6,558			6,278
Taxes other than income taxes	6,836			6,500
Total operating expenses	60,655			56,801
Operating income	17,965			18,554
Other Income and Deductions:
Other income	822			593
Other (deductions)	(90		)	15
Net other income and deductions	732			608
Interest Charges	7,404			7,369
Earnings before Income Taxes	11,293			11,793
Income Taxes	3,689			4,337
Net Earnings	$	7,604		$	7,456

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,
	2017			2016
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	7,604		$	7,456
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	15,921			14,936
Deferred income tax expense	2,746			194
Allowance for equity funds used during construction and other, net	(168		)	—
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	3,138			2,798
Materials and supplies	(247		)	3,344
Other current assets	(838		)	(1,842		)
Other assets	(2,042		)	(2,694		)
Accounts payable	(788		)	(3,788		)
Accrued interest and taxes	(3,991		)	939
Other current liabilities	134			163
Other liabilities	361			81
Net cash flows from operating activities	21,830			21,587
Cash Flows From Investing Activities:
Utility plant additions	(36,345		)	(32,947		)
Net cash flows from investing activities	(36,345		)	(32,947		)
Cash Flow From Financing Activities:
Revolving credit facilities borrowings (repayments), net	22,000			(44,000		)
Short-term borrowings (repayments) – affiliate, net	1,700			(3,900		)
Long-term borrowings	—			60,000
Dividends paid	(9,855		)	—
Other, net	—			(740		)
Net cash flows from financing activities	13,845			11,360
Change in Cash and Cash Equivalents	(670		)	—
Cash and Cash Equivalents at Beginning of Period	671			1
Cash and Cash Equivalents at End of Period	$	1		$	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	2,584		$	1,719
Income taxes paid (refunded), net	$	—		$	—
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	2,235		$	2,047

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, 2017		December 31, 2016
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	671
Accounts receivable	20,955		22,009
Unbilled revenues	7,911		9,995
Other receivables	2,831		2,090
Materials and supplies	3,822		8,626
Regulatory assets	910		413
Other current assets	630		1,031
Total current assets	37,060		44,835
Other Property and Investments:
Other investments	231		231
Non-utility property	2,240		2,240
Total other property and investments	2,471		2,471
Utility Plant:
Plant in service and plant held for future use	1,389,854		1,380,584
Less accumulated depreciation and amortization	439,781		429,397
	950,073		951,187
Construction work in progress	38,832		16,978
Net utility plant	988,905		968,165
Deferred Charges and Other Assets:
Regulatory assets	135,649		135,810
Goodwill	226,665		226,665
Other deferred charges	5,305		5,277
Total deferred charges and other assets	367,619		367,752
	$	1,396,055	$	1,383,223

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, 2017		December 31, 2016
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	22,000	$	—
Short-term debt – affiliate	6,300		4,600
Accounts payable	8,634		16,709
Affiliate payables	2,854		3,793
Accrued interest and taxes	41,590		45,581
Regulatory liabilities	—		92
Other current liabilities	3,300		2,134
Total current liabilities	84,678		72,909
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	420,950		420,875
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	248,585		245,785
Regulatory liabilities	32,403		31,948
Asset retirement obligations	769		754
Accrued pension liability and postretirement benefit cost	10,436		11,417
Other deferred credits	7,250		6,300
Total deferred credits and other liabilities	299,443		296,204
Total liabilities	805,071		789,988
Commitments and Contingencies (See 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	454,166		454,166
Retained earnings	136,754		139,005
Total common stockholder’s equity	590,984		593,235
	$	1,396,055	$	1,383,223

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, 2016	$	64	$	454,166	$	139,005		$	593,235
Net earnings	—		—		7,604			7,604
Dividends declared on common stock	—		—		(9,855		)	(9,855		)
Balance at March 31, 2017	$	64	$	454,166	$	136,754		$	590,984

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, 2017 and December 31, 2016 and the consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2017 and 2016. 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 2016 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2017 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual 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 2016 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 5) and, through January 15, 2016, the PVNGS Capital Trust. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated. See Note 14.

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)

New Accounting Pronouncements

Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below.

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

In May 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. When it becomes effective, the new standard will replace most existing revenue recognition guidance in GAAP. Since the issuance of ASU No. 2014-09, the FASB issued a one-year deferral in the effective date and has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. The new standard can be applied retrospectively to each prior period presented or on a modified retrospective basis with a cumulative effect adjustment to retained earnings on the date of adoption. The Company has not made a final decision on the transition method, but currently anticipates using the modified retrospective method. The Company will adopt the standard on January 1, 2018, its required effective date.

The Company has completed its initial assessment and made significant progress toward completing the evaluation of its revenues for potential changes to the amounts and timing of revenue recognition under the new guidance. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification. These industry specific issues include the impacts of the new guidance on its accounting for CIAC, collectability, and the presentation of revenues associated with “alternative revenue programs,” which primarily result from its approved rate rider programs. The Company is working towards completing its evaluation and drafting its revenue recognition disclosures under the new standard. The Company has not finalized conclusions and has not yet completely determined the effect of the standard on its financial reporting, but does not anticipate significant changes in revenue recognition associated with retail electric service rates or expect difficulty in completing this project by the required January 1, 2018 implementation date.

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

In January 2016, the FASB issued ASU No. 2016-01, which makes targeted improvements to GAAP regarding financial instruments. The new standard eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and will require those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. Also, the new standard will revise certain presentation and disclosure requirements. Under the new standard, accounting for investments in debt securities remains essentially unchanged. PNM currently classifies the investments held in the NDT and coal mine reclamation trusts as available for sale securities. Unrealized losses on these securities are recorded immediately through earnings and unrealized gains are recorded in AOCI until the securities are sold. The Company will adopt the new standard on January 1, 2018, its required effective date. At that time any unrealized gains, net of income taxes, recorded in AOCI related to equity securities will be reclassified to retained earnings as a cumulative effect adjustment and, thereafter, changes in the value of equity securities will be recorded in the Consolidated Statements of Earnings. The amount of the cumulative adjustment upon adoption will depend on the amounts recorded in AOCI at that time, but PNM had unrealized gains on equity securities, net of income taxes, recorded in AOCI of $6.8 million at March 31, 2017.

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

In February 2016, the FASB issued ASU No. 2016-02, which will change how lessees account for leases. The ASU will require that a liability be recorded on the balance sheet for all leases based on the present value of future lease obligations. A corresponding right-of-use asset will also be recorded. Amortization of the lease obligation and the right-of-use asset for certain leases, primarily those classified as operating leases, will be on a straight-line basis, which is not expected to have a significant impact on the statements of earnings or cash flows, whereas other leases will be required to be accounted for as financing

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)

arrangements similar to the accounting treatment for capital leases under current GAAP. Also, the new standard will revise certain disclosure requirements. Although early adoption of the standard is permitted, the Company does not currently plan to adopt this standard prior to January 1, 2019, its required effective date. At adoption of the ASU, leases will be recognized and measured as of the earliest period presented using a modified retrospective approach.

As discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, the Company has operating leases of office buildings, vehicles, equipment, and certain rights-of-way. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification. The Company has formed a project team, conducted outreach activities across its lines of business, and made significant progress in identifying arrangements, in addition to its existing operating lease arrangements, that may be classified as leases under the ASU. It is likely the arrangements currently classified as leases will continue to be recognized as leases under the new ASU. It is possible that other contractual arrangements not previously meeting the lease definition may contain elements that qualify as leases under ASU 2016-02 and that previously identified operating leases may be classified as financing leases under the new standard. The Company is in the process of analyzing each of the identified contractual arrangement to determine if it contains lease elements under the new standard and to quantify the potential impacts of identified lease arrangements. The Company anticipates this process will continue through the remainder of 2017 and possibly into 2018. Upon completion of that process, the Company will provide additional information about the expected financial impact of this ASU.

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

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

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

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

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

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

Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350)

In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting

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)

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 this ASU 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 must adopt this ASU in 2020, but early adoption is permitted. The Company currently anticipates adopting this ASU in 2020. However, if there is an indication of potential impairment of goodwill as a result of an annual impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this ASU.

Accounting Standards Update 2017-07 – Compensation – Retirement Benefits (Topic 715)

In March 2017, the FASB issued ASU 2017-07 to improve the presentation of net periodic pension and other postretirement benefit costs. Currently, the Company presents all of its net periodic benefit costs as administrative and general expenses on its Condensed Consolidated Statements of Earnings, net of amounts capitalized to construction and other accounts. The amendments in this ASU require the service cost component of net benefit costs be presented in the same line item or items as compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of operating income with disclosures identifying where the other components of net benefit cost have been presented. The ASU also limits capitalization to only the service cost component of benefit costs. PNMR and its subsidiaries maintain qualified defined benefit pension and OPEB plans. Currently, net periodic benefit cost for the Company’s defined benefit pension plans do not include a service cost component and there is only a minor amount of service cost for the OPEB plans. Additional information about the Company’s plans is discussed in Note 12 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 10. The ASU requires retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit cost. The Company must adopt this ASU beginning January 1, 2018. The Company is in the process of analyzing the impacts of this new standard, including the treatment of benefit costs by the NMPRC, PUCT, and FERC in the regulatory process.

Accounting Standards Update 2017-08 - Receivables - Nonrefundable Fees and Other Costs (Topic 310-20) Premium Amortization on Purchased Callable Debt Securities

In March 2017, the FASB issued ASU No. 2017-08. The ASU amends the amortization period for certain purchased callable debt securities held at a premium. Under current GAAP, some entities amortize the premium as an adjustment of yield over the contractual life of the security. The update requires premiums to be amortized over the period to the earliest call date. The new standard is effective for the Company beginning on January 1, 2019. Early adoption is permitted including adoption in an interim period. The Company is in the process of analyzing the impacts of this new standard.

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)

(2) 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,
	2017		2016
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	22,862	$	10,546
Average Number of Common Shares:
Outstanding during period	79,654		79,654
Vested awards of restricted stock	112		104
Average Shares – Basic	79,766		79,758
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	346		406
Average Shares – Diluted	80,112		80,164
Net Earnings Per Share of Common Stock:
Basic	$	0.29	$	0.13
Diluted	$	0.29	$	0.13

(3) 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.

Corporate and Other

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

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

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)

PNMR SEGMENT INFORMATION

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended March 31, 2017
Electric operating revenues	$	251,558		$	78,620		$	—		$	330,178
Cost of energy	81,317			21,487			—			102,804
Utility margin	170,241			57,133			—			227,374
Other operating expenses	95,894			23,797			(4,660		)	115,031
Depreciation and amortization	36,016			15,371			4,996			56,383
Operating income (loss)	38,331			17,965			(336		)	55,960
Interest income	2,816			—			2,065			4,881
Other income (deductions)	7,683			732			(335		)	8,080
Interest charges	(21,012		)	(7,404		)	(3,284		)	(31,700		)
Segment earnings (loss) before income taxes	27,818			11,293			(1,890		)	37,221
Income taxes (benefit)	7,708			3,689			(622		)	10,775
Segment earnings (loss)	20,110			7,604			(1,268		)	26,446
Valencia non-controlling interest	(3,452		)	—			—			(3,452		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	16,526		$	7,604		$	(1,268	)	$	22,862
At March 31, 2017:
Total Assets	$	4,870,201		$	1,396,055		$	211,423		$	6,477,679
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended March 31, 2016
Electric operating revenues	$	235,606		$	75,355		$	—		$	310,961
Cost of energy	72,444			19,925			—			92,369
Utility margin	163,162			55,430			—			218,592
Other operating expenses	108,001			22,368			(3,114		)	127,255
Depreciation and amortization	31,864			14,508			3,457			49,829
Operating income (loss)	23,297			18,554			(343		)	41,508
Interest income	1,522			—			2,100			3,622
Other income (deductions)	7,943			608			(1,068		)	7,483
Interest charges	(21,591		)	(7,369		)	(2,531		)	(31,491		)
Segment earnings (loss) before income taxes	11,171			11,793			(1,842		)	21,122
Income taxes (benefit)	3,610			4,337			(790		)	7,157
Segment earnings (loss)	7,561			7,456			(1,052		)	13,965
Valencia non-controlling interest	(3,287		)	—			—			(3,287		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	4,142		$	7,456		$	(1,052	)	$	10,546
At March 31, 2016:
Total Assets	$	4,719,346		$	1,312,402		$	242,064		$	6,273,812
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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) Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2017 and 2016 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, 2016	$	4,320		$	(96,748	)	$	(92,428	)	$	(23	)	$	(92,451	)
Amounts reclassified from AOCI (pre-tax)	(2,763		)	1,618			(1,145		)	112			(1,033		)
Income tax impact of amounts reclassified	1,078			(631		)	447			(44		)	403
Other OCI changes (pre-tax)	7,766			—			7,766			(185		)	7,581
Income tax impact of other OCI changes	(3,030		)	—			(3,030		)	72			(2,958		)
Net after-tax change	3,051			987			4,038			(45		)	3,993
Balance at March 31, 2017	$	7,371		$	(95,761	)	$	(88,390	)	$	(68	)	$	(88,458	)

Balance at December 31, 2015	$	17,346		$	(88,822	)	$	(71,476	)	$	44		$	(71,432	)
Amounts reclassified from AOCI (pre-tax)	(11,210		)	1,376			(9,834		)	146			(9,688		)
Income tax impact of amounts reclassified	4,374			(537		)	3,837			(57		)	3,780
Other OCI changes (pre-tax)	5,458			—			5,458			(1,289		)	4,169
Income tax impact of other OCI changes	(2,130		)	—			(2,130		)	503			(1,627		)
Net after-tax change	(3,508		)	839			(2,669		)	(697		)	(3,366		)
Balance at March 31, 2016	$	13,838		$	(87,983	)	$	(74,145	)	$	(653	)	$	(74,798	)

Pre-tax amounts reclassified from AOCI related to “Unrealized Gains on Available-for-Sale Securities” are included in “Gains on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “Pension Liability Adjustment” are reclassified to “Operating Expenses – Administrative and general” in the Condensed Consolidated Statements of Earnings. For the three months ended March 31, 2017 and 2016, 19.8% and 22.7% of the pension amounts reclassified were capitalized into construction work in process and 5.4% and 2.6% were capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC and capitalized interest. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes” in the Condensed Consolidated Statements of Earnings.

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)

(5) 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 9 of the Notes to Consolidated Financial Statements in the 2016 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, 2017 and 2016, PNM paid $4.9 million and $4.8 million for fixed charges and $0.1 million and $0.2 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. 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 (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market value.

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,
	2017			2016
	(In thousands)
Operating revenues	$	4,927		$	4,937
Operating expenses	(1,475		)	(1,650		)
Earnings attributable to non-controlling interest	$	3,452		$	3,287

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)

Financial Position

	March 31,		December 31,
	2017		2016
	(In thousands)
Current assets	$	2,841	$	2,551
Net property, plant, and equipment	66,237		66,947
Total assets	69,078		69,498
Current liabilities	734		578
Owners’ equity – non-controlling interest	$	68,344	$	68,920

Westmoreland San Juan LLC (“WSJ”) and SJCC

As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS from SJCC under a coal supply agreement (“CSA”). That section includes information on the purchase of SJCC by WSJ on January 31, 2016, as well as a $125.0 million loan (the “Westmoreland Loan”) from NM Capital, a subsidiary of PNMR, to WSJ, which loan provided substantially all of the funds required for the SJCC purchase, and the issuance of $30.3 million in letters of credit to facilitate the issuance of reclamation bonds required in order for SJCC to mine coal to be supplied to SJGS. The Westmoreland Loan and the letters of credit support result in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital could be subject to loss in the event of a default by WSJ under the Westmoreland Loan and/or performance under the letter of credit support was required.  Principal payments under the Westmoreland Loan began on August 1, 2016 and are required quarterly thereafter. Interest is also paid quarterly beginning on May 3, 2016.

At March 31, 2017, the amount outstanding under the Westmoreland Loan was $85.4 million. In addition, interest receivable of $1.4 million is included in Other receivables. The Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. A principal payment of $9.6 million plus interest of $2.2 million is due on May 2, 2017. As of April 24, 2017, $11.8 million was held in a SJCC bank account that is restricted solely to be used to service the Westmoreland Loan. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations.  In such event, NM Capital would likely engage a third-party mining company to operate SJCC so that operations of the mine are not disrupted. The acquisition of SJCC by WSJ for approximately $125.0 million is a recently negotiated, arms-length transaction between Westmoreland and BHP, which amount should approximate the fair value of SJCC at the date of acquisition.  If WSJ were to default, NM Capital should be able to acquire assets of approximately the value of the Westmoreland Loan without a significant loss. Furthermore, PNMR considers the possibility of loss under the letters of credit support to be remote since the purpose of posting the bonds is to provide assurance that SJCC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the CSA. Also, much of the mine reclamation activities will not be performed for many years in the future, including after the expiration of the CSA and the final maturity of the Westmoreland Loan. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations.

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

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)

its economic performance will be improved.  Conversely, if SJCC cannot mine as efficiently as anticipated, its economic performance will be negatively impacted.  Accordingly, PNMR believes Westmoreland is the primary beneficiary of WSJ and, therefore, WSJ and SJCC are not consolidated by either PNMR or PNM. The amounts outstanding under the Westmoreland Loan and the letter of credit support constitute PNMR’s maximum exposure to loss from the VIEs.

(6) Lease Commitments

The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS. All of the Company’s leases are currently accounted for as operating leases. See Note 1. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, including PNM’s actions with regard to renewal and purchase options under the PVNGS leases.

The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. The four Unit 1 leases have been extended to expire on January 15, 2023 and one of the Unit 2 leases has been extended to expire on January 15, 2024. For the other three PVNGS Unit 2 leases, PNM exercised its fair market value options to purchase the assets underlying those leases on the expiration date of the original leases. On January 15, 2016, PNM paid $78.1 million to the lessor under one lease for 31.3 MW of the entitlement from PVNGS Unit 2 and $85.2 million to the lessors under the other two leases for 32.8 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.

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, 2017, amounts due to the lessors under the circumstances described above would be up to $173.0 million, payable on July 15, 2017 in addition to the scheduled lease payments due on July 15, 2017.

(7) Fair Value of Derivative and Other Financial Instruments

Additional information concerning the Company’s energy related derivative contracts and other financial instruments is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2016 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 retail and wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its wholesale customers not covered under a FPPAC. However, as discussed below, PNM has hedging arrangements for the output of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers. Beginning January

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)

1, 2018, PNM expects to be exposed to market risk for the 65 MW of SJGS Unit 4 that is anticipated to be transferred to PNM from PNMR Development (Note 11). PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases.

Commodity Risk

Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.

Accounting for Derivatives

Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. During the three months ended March 31, 2017 and the year ended December 31, 2016, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. The Company has no trading transactions.

Commodity Derivatives

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

	Economic Hedges
	March 31, 2017			December 31, 2016
PNMR and PNM	(In thousands)
Current assets	$	4,586		$	5,224
Current liabilities	(360		)	(2,339		)
Net	$	4,226		$	2,885

Included in the above table are $2.0 million and $2.7 million of current assets at March 31, 2017 and December 31, 2016 related to contracts for the sale of energy from PVNGS Unit 3 through 2017 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at March 31, 2017 and December 31, 2016.

At March 31, 2017 and December 31, 2016, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at March 31, 2017 and December 31, 2016, amounts posted as cash collateral under margin arrangements were $1.5 million and $2.6 million for both PNMR and PNM. At March 31, 2017 and December 31, 2016, obligations to return

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)

cash collateral were $0.1 million and $0.1 million for both PNMR and PNM. Cash collateral amounts are included in other current assets and other current liabilities on the 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. The table above includes $0.1 million of current assets and less than $0.1 million of current liabilities at March 31, 2017 and $0.2 million of current assets and $0.1 million of current liabilities at December 31, 2016 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.

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

	Economic Hedges
	Three Months Ended
	March 31,
	2017		2016
PNMR and PNM	(In thousands)
Electric operating revenues	$	3,341	$	2,684
Cost of energy	11		(145		)
Total gain (loss)	$	3,352	$	2,539

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

	Economic Hedges
	MMBTU	MWh
PNMR and PNM
March 31, 2017	100,000	(1,834,125	)
December 31, 2016	254,100	(2,471,600	)

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

The Company 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. Contractual liability represents those commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. Cash collateral that has been posted under the existing contracts does not reflect letters of credit under the Company’s revolving credit facilities that may have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions. At March 31, 2017 and December 31, 2016, the Company had no contractual liability, posted cash collateral, or net exposure related to these contingent requirements for contracts in net liability positions.

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently included in retail rates, that unit’s power is being sold in the wholesale market. PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers beginning on January 1, 2018. As of March 31, 2017, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2017, at market price plus a premium.  Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates for substantially all of the sales through 2017, which average approximately $29 per MWh.

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)

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. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and trusts for PNM’s share of final reclamation costs related to the coal mines serving SJGS and Four Corners (Note 11). At March 31, 2017 and December 31, 2016, the fair value of available-for-sale securities included $266.1 million and $253.9 million for the NDT and $20.0 million and $19.1 million for the mine reclamation trusts. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	March 31, 2017				December 31, 2016
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	8,047	$	—	$	23,683
Equity securities:
Domestic value	3,044		70,043		1,135		34,796
Domestic growth	4,438		65,127		3,032		47,595
International and other	3,555		36,442		2,029		27,481
Fixed income securities:
U.S. Government	178		31,410		115		40,962
Municipals	617		33,218		585		43,789
Corporate and other	574		41,812		553		54,671
	$	12,406	$	286,099	$	7,449	$	272,977

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the decrease in realized impairment losses of$1.1 millionand $1.6 million for the three months ended March 31, 2017 and 2016.

	Three Months Ended
	March 31,
	2017			2016
PNMR and PNM	(In thousands)
Proceeds from sales	$	266,388		$	124,900
Gross realized gains	$	8,645		$	10,716
Gross realized (losses)	$	(3,085	)	$	(6,116	)

Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. At March 31, 2017 and December 31, 2016, held-to-maturity securities consist of the Westmoreland Loan.

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

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)

At March 31, 2017, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR
	(In thousands)
Within 1 year	$	3,852	$	—
After 1 year through 5 years	23,629		96,444
After 5 years through 10 years	29,024		—
After 10 years through 15 years	3,963		—
After 15 years through 20 years	8,728		—
After 20 years	37,244		—
	$	106,440	$	96,444

Fair Value Disclosures

The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models. The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the three months ended March 31, 2017 and the year ended December 31, 2016.

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

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 on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at March 31, 2017 and December 31, 2016 for items recorded at fair value.

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
PNMR and PNM	(In thousands)
March 31, 2017
Available-for-sale securities
Cash and cash equivalents	$	8,047		$	8,047	$	—
Equity securities:
Domestic value	70,043			70,043		—
Domestic growth	65,127			65,127		—
International and other	36,442			33,212		3,230
Fixed income securities:
U.S. Government	31,410			30,179		1,231
Municipals	33,218			—		33,218
Corporate and other	41,812			—		41,812
	$	286,099		$	206,608	$	79,491
Commodity derivative assets	$	4,586		$	—	$	4,586
Commodity derivative liabilities	(360		)	—		(360		)
Net	$	4,226		$	—	$	4,226
December 31, 2016
Available-for-sale securities
Cash and cash equivalents	$	23,683		$	23,683	$	—
Equity securities:
Domestic value	34,796			34,796		—
Domestic growth	47,595			47,595		—
International and other	27,481			27,481		—
Fixed income securities:
U.S. Government	40,962			39,723		1,239
Municipals	43,789			—		43,789
Corporate and other	54,671			23,158		31,513
	$	272,977		$	196,436	$	76,541
Commodity derivative assets	$	5,224		$	—	$	5,224
Commodity derivative liabilities	(2,339		)	—		(2,339		)
Net	$	2,885		$	—	$	2,885

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)

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

					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
March 31, 2017	(In thousands)
PNMR
Long-term debt	$	2,384,160	$	2,525,916	$	—	$	2,525,916	$	—
Westmoreland Loan	$	85,410	$	96,444	$	—	$	—	$	96,444
Other investments	$	419	$	1,051	$	419	$	—	$	632
PNM
Long-term debt	$	1,631,972	$	1,728,276	$	—	$	1,728,276	$	—
Other investments	$	188	$	188	$	188	$	—	$	—
TNMP
Long-term debt	$	420,950	$	464,877	$	—	$	464,877	$	—
Other investments	$	231	$	231	$	231	$	—	$	—
December 31, 2016
PNMR
Long-term debt	$	2,392,712	$	2,540,693	$	—	$	2,540,693	$	—
Westmoreland Loan	$	95,000	$	100,893	$	—	$	—	$	100,893
Other investments	$	547	$	1,164	$	547	$	—	$	617
PNM
Long-term debt	$	1,631,369	$	1,730,157	$	—	$	1,730,157	$	—
Other investments	$	316	$	316	$	316	$	—	$	—
TNMP
Long-term debt	$	420,875	$	468,329	$	—	$	468,329	$	—
Other investments	$	231	$	231	$	231	$	—	$	—

(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. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 13 of the Notes to Consolidated Financial Statements in the 2016 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, the awards vest ratably over three years from the grant date of the award. However, awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards. Beginning with 2017 awards, the vesting period for awards of restricted stock to non-employee members of the Board will be one year.

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

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)

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, 2017 and December 31, 2016, PNMR had unrecognized expense related to stock awards of $6.9 million and $4.5 million, which are expected to be recognized over an average of 2.4 and 1.8 years.

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

The FASB issued Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718) to simplify several aspects of the accounting for share-based payment transactions and eliminate diversity in practice. PNMR’s historical accounting for stock compensation complies with ASU 2016-09, except for the treatment of the income tax consequences of awards and the presentation of reductions to taxes payable on the Consolidated Statements of Cash Flows. Prior to ASU 2016-09, benefits resulting from income tax deductions in excess of compensation cost recognized under GAAP for vested restricted stock and on exercised stock options (“excess tax benefits”) were recorded to equity provided the excess tax benefits reduced income taxes payable. Deficiencies resulting from tax deductions related to stock awards that were below recognized compensation cost upon vesting and on canceled stock options were recorded to equity. PNMR has not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. ASU 2016-09 requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as cash flows from operating activities. PNMR adopted ASU 2016-09 as of January 1, 2017 and recorded excess tax benefits of $1.8 million in the three months ended March 31, 2017 of which $1.3 million was recorded at PNM and $0.5 million at TNMP. As required by ASU 2016-09, PNMR recorded the excess tax benefits that were not recognized in prior years, due to its net operating loss position, as a cumulative effect adjustment of $10.4 million, increasing retained earnings and decreasing accumulated deferred income taxes on the Condensed Consolidated Balance Sheets. When excess tax benefits are used to reduce income taxes payable, the benefit will be reflected in cash flows from operating activities.

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

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

	Three Months Ended March 31,
Restricted Shares and Performance Based Shares	2017			2016
Expected quarterly dividends per share	$	0.2425		$	0.2200
Risk-free interest rate	1.58		%	1.00		%
Market-Based Shares
Dividend yield	2.67		%	2.74		%
Expected volatility	20.80		%	20.44		%
Risk-free interest rate	1.54		%	0.97		%

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, 2017:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2016	218,316		$	27.59	305,874		$	12.29
Granted	231,107		$	22.12	—		$	—
Exercised	(248,003	)	$	20.26	(59,600	)	$	18.66
Forfeited	(822	)	$	27.86	—		$	—
Expired	—		$	—	(3,000	)	$	30.50
Outstanding at March 31, 2017	200,598		$	30.35	243,274		$	10.51

PNMR’s stock-based compensation program provides for performance and market targets through 2019. Included as granted and as exercised in the above table are 49,682 previously awarded shares that were earned for the 2014 through 2016 performance measurement period and ratified by the Board in February 2017 (based upon achieving market targets at “target” levels, weighted at 60%, and not meeting performance targets, weighted at 40%). Excluded from the above table are maximums of 163,712, 137,036, and 133,632 shares for the three-year performance periods ending in 2017, 2018, and 2019 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she was to receive 135,000 shares of PNMR’s common stock if PNMR met specific market targets at the end of 2016 and she remained an employee of the Company. Under the agreement, she received 35,000 of the total shares in 2015 since PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2016 and the Board ratified her receiving the remaining 100,000 shares, which is included in the above table, in February 2017. The retention award was made under the PEP and was approved by the Board on February 28, 2012.

Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieved the specific performance target for the period from January 1, 2015 through December 31, 2016, he was to receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. The specified market target was achieved at the end of 2016 and the Board ratified him receiving $100,000 of PNMR common stock in February 2017 based on a market per share value of $36.30 on the grant date of March 3, 2017, or 2,754 shares, which is included in the above table. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

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

At March 31, 2017, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.4 million with a weighted-average remaining contract life of 2.1 years. At March 31, 2017, no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date.

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)

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	2017		2016
Weighted-average grant date fair value	$	22.12	$	26.05
Total fair value of restricted shares that vested (in thousands)	$	5,024	$	4,131
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)	$	945	$	853

(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 revolving credit facilities and the Company’s term loans contains a single financial covenant, which requires the maintenance of a debt-to-capital ratio of less than or equal to 65%, and generally also include customary covenants, events of default, cross default provisions, and change of control provisions. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. Additional information concerning financing activities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K.

Financing Activities

On March 9, 2015, PNMR entered into a $150.0 million Term Loan Agreement (“PNMR 2015 Term Loan Agreement”) between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and administrative agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate and must be repaid on or before March 9, 2018. In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 1.927%, subject to change if there is a change in PNMR’s credit rating, for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018. This hedge is accounted for as a cash-flow hedge and had a fair value gain of $0.2 million at March 31, 2017, which is included in Other current assets on the Condensed Consolidated Balance Sheets, and a fair value loss of less than $0.1 million at December 31, 2016. 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.

The interest rate on the PNMR 2015 Term Loan Agreement was 1.75% at March 31, 2017. The $100.0 million PNMR 2016 Two-Year Term Loan and the $175.0 million PNM 2016 Term Loan Agreement also bear interest at variable rates, which were 1.93% and 1.59% at March 31, 2017.

As discussed in Note 11, NM Capital, a wholly owned subsidiary of PNMR, entered into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent, as of February 1, 2016. The BTMU Term Loan Agreement has a maturity date of February 1, 2021 and bears interest at a rate based on LIBOR plus a customary spread, which aggregated 3.79% at March 31, 2017. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. The BTMU Term Loan Agreement and the guaranty include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio of 65%, and customary events of default, a cross default provision, and a change of control provision consistent with PNMR’s other term loan agreements. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding of $125.0 million (the “Westmoreland Loan”) to a ring-fenced, bankruptcy-remote, sp

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)

ecial-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price of the stock of SJCC. The BTMU Term Loan Agreement requires that NM Capital utilize all amounts, less taxes and fees, it receives under the Westmoreland Loan to repay the BTMU Term Loan Agreement. The principal balance outstanding under the BTMU Term Loan Agreement was $82.8 million at March 31, 2017. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $33.5 million on the BTMU Term Loan Agreement in the twelve months ended March 31, 2018.

On October 21, 2016, PNMR entered into letter of credit arrangements with JPMorgan Chase Bank, N.A. (the “JPM LOC Facility”) under which letters of credit aggregating $30.3 million were issued to facilitate the posting of reclamation bonds, which SJCC is required to post in connection with permits relating to the operation of the San Juan mine (Note 11).

On March 9, 2017, PNMR entered into a four-year hedging agreement whereby it effectively established a fixed interest rate of 1.926% plus a customary spread, subject to change if there is a change in PNMR’s credit rating, for $50.0 million of its variable rate short-term debt. This hedge is accounted for as a cash-flow hedge and had a fair value loss of $0.4 million at March 31, 2017, which is included in Other current liabilities on the Condensed Consolidated Balance Sheets. The fair value was 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.

Short-term Debt and Liquidity

Currently, the PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. In November 2016, PNMR and PNM entered into agreements to extend the maturity of both facilities from October 31, 2020 to October 31, 2021. However, one lender, whose current commitment is $10.0 million under the PNMR Revolving Credit Facility and $40.0 million under the PNM Revolving Credit Facility, did not agree to extend its commitments beyond October, 31, 2020. Unless one or more of the other current lenders or a new lender assumes the commitments of the non-extending lender, the financing capacities will be reduced to $290.0 million for the PNMR Revolving Credit Facility and $360.0 million for the PNM Revolving Credit Facility from November 1, 2020 through October 31, 2021. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. The TNMP Revolving Credit Facility matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At March 31, 2017, the weighted average interest rate was 2.19% for the PNMR Revolving Credit Facility, 2.11% for the PNM Revolving Credit Facility, 1.94% for the TNMP Revolving Credit Facility, and 1.83% for the PNMR 2016 One-Year Term Loan, which matures in December 2017. Short-term debt outstanding consisted of:

	March 31,		December 31,
Short-term Debt	2017		2016
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	16,200	$	35,000
PNM New Mexico Credit Facility	—		26,000
TNMP Revolving Credit Facility	22,000		—
PNMR:
PNMR Revolving Credit Facility	164,900		126,100
PNMR 2016 One-Year Term Loan	100,000		100,000
	$	303,100	$	287,100

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $6.2 million, $2.5 million, and $0.1 million at March 31, 2017 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of March 31, 2017, TNMP had intercompany borrowings from PNMR of $6.3 million.

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 April 24, 2017, PNMR, PNM, and TNMP had $137.7 million, $389.7 million, and $34.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $43.0 million of availability under the PNM New Mexico Credit Facility. Total availability at April 24, 2017, on a consolidated basis, was $605.3 million for PNMR. As of April 24, 2017, TNMP had borrowings of $5.0 million from PNMR under its intercompany loan agreement. At April 24, 2017, PNMR, PNM, and TNMP had consolidated invested cash of $1.5 million, none, and none.

PNM has maturities, mandatory remarketings, and other repayments of short-term and long-term debt aggregating $232.0 million in the period from April 1, 2017 through March 31, 2018 and $450.0 million in the remainder of 2018. In addition, the $50.0 million PNM New Mexico Credit Facility expires in January 2018. PNMR has maturities and other repayments of short-term and long-term debt aggregating $283.5 million in the period from April 1, 2017 through March 31, 2018 and $106.8 million in the remainder of 2018, including anticipated repayments on the BTMU Term Loan Agreement. TNMP has no required principal payments on its long-term debt through 2018, but the $75.0 million TNMP Revolving Credit Facility currently expires in September 2018. Additional information on debt maturities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2016 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.

Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. See New Accounting Pronouncements in Note 1.

PNM Plans

The following tables present the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2017			2016			2017			2016			2017		2016
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	24		$	35		$	—	$	—
Interest cost	6,727			7,577			1,006			1,087			174		203
Expected return on plan assets	(8,451		)	(8,854		)	(1,308		)	(1,371		)	—		—
Amortization of net (gain) loss	4,001			3,455			921			286			78		64
Amortization of prior service cost	(241		)	(241		)	(416		)	(7		)	—		—
Net periodic benefit cost	$	2,036		$	1,937		$	227		$	30		$	252	$	267

PNM did not make any contributions to its pension plan trustin the three months ended March 31, 2017 and 2016 and does not anticipate making any contributions to the pension plan in 2017-2021, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.1% to 4.9%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made no contributions to the OPEB trust in the three months ended March 31, 2017 and$0.8 millionin the three months ended March 31, 2016. PNM does not expect to make any contributions to the OPEB trust in 2017-2021.  Disbursements under the executive retirement program, which are

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)

funded by PNM and considered to be contributions to the plan, were $0.5 million and$0.5 millionin the three months ended March 31, 2017 and 2016 and are expected to total $1.5 million during 2017 and $5.8 million for 2018-2021.

TNMP Plans

The following tables present the components of the TNMP Plans’ net periodic benefit cost (income):

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2017			2016			2017			2016			2017		2016
	(In thousands)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	—		$	—		$	36		$	46		$	—	$	—
Interest cost	722			826			139			169			8		10
Expected return on plan assets	(945		)	(986		)	(114		)	(122		)	—		—
Amortization of net (gain) loss	231			175			(20		)	(10		)	2		1
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost (Income)	$	8		$	15		$	41		$	83		$	10	$	11

TNMP did not make any contributions to its pension plan trust in the three months ended March 31, 2017 and 2016 and does not anticipate making any contributions in 2017-2021, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.1% to 4.9%. 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 $0.7 million to the OPEB trust in the three months ended March 31, 2017 and no contribution in the three months ended March 31, 2016. TNMP does not expect to make any additional contributions to the OPEB trust in 2017 and expects to make contributions totaling $1.4 million for 2018-2021. 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, 2017 and 2016 and are expected to total $0.1 million during 2017 and $0.4 million in 2018-2021.

(11) Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 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. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, or other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed,

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)

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 2016 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 DOE entered into a settlement agreement, which establishes a process for the payment of claims for costs incurred through December 31, 2016. The settlement agreement has been extended to 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 fuel is consumed. At March 31, 2017 and December 31, 2016, PNM had a liability for interim storage costs of $12.0 million and $12.1 million included in other deferred credits.

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

On June 8, 2012, the DC Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (the “Waste Confidence Decision”). The DC Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’s actions. The DC Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient and, therefore, remanded the Waste Confidence Decision update for further action consistent with NEPA. On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision.

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

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)

NRC and the United States Court of Appeals. On May 19, 2016, the NRC denied petitions filed by multiple petitioners to revise the August 2014 rule. The DC Circuit issued an order upholding the August 2014 rule on June 3, 2016 and denied a subsequent petition for rehearing on August 8, 2016.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged, in the DC Circuit, DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval, as ordered by the DC Circuit. On May 16, 2014, the DOE adjusted the fee to zero. PNM anticipates challenges to this action and is unable to predict its ultimate outcome.

The Clean Air Act

Regional Haze

In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.

SJGS

BART Compliance –SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K contains detailed information concerning the BART compliance process, including interactions with governmental agencies responsible for environmental oversight and the NMPRC approval process. In December 2015, PNM received NMPRC approval for the plan to comply with the EPA regional haze rule at SJGS. Under the approved plan, the installation of selective non-catalytic reduction technology (“SNCR”) was required on SJGS Units 1 and 4, which was completed in early 2016, and Units 2 and 3 are to be retired by the end of 2017. In addition to the required SNCR equipment, the NSR permit, which was required to be obtained in order to install the SNCRs, specified that SJGS Units 1 and 4 be converted to balanced draft technology (“BDT”). PNM’s share of the total costs for SNCRs and BDT equipment was $77.9 million. See Note 12 for information concerning the NMPRC’s treatment of BDT in PNM’s NM 2015 Rate Case. Although operating costs will be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 have increased with the installation of SNCR and BDT equipment.

On December 16, 2015, the NMPRC issued an order regarding SJGS. As provided in that order:

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

• PNM is granted a CCN to acquire an additional 132 MW in SJGS Unit 4, effective January 1, 2018, with an initial book value of zero, plus the costs of SNCR and other capital additions

• PNM is granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017, including transmission assets associated with PVNGS Unit 3, (currently estimated to aggregate approximately $156 million)

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

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)

within six months (to facilitate the 2018 filing PNM is developing two resource portfolios in its 2017 IRP, which is discussed in Note 12, to be filed in July 2017, one with SJGS continuing beyond mid-2022 and one where it is shut down)

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

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

• PNM will accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022 (cost recovery for PNM’s BDT project is discussed in Note 12)

• PNM will not recover approximately $20 million of other costs incurred in connection with CAA compliance

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

At December 31, 2015, PNM recorded losses for regulatory disallowances and restructuring costs, aggregating $165.7 million, reflecting a $127.6 million regulatory disallowance to reflect the write-off of the 50% of the estimated December 31, 2017 net book value that will not be recovered, the other unrecoverable costs, and the $16.5 million increase in the estimated liability recorded for coal mine reclamation resulting from the new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”). The ultimate amount of the regulatory disallowance will be dependent on the actual December 31, 2017 net undepreciated book values of SJGS Units 2 and 3. Accordingly, the amount initially recorded will be adjusted periodically to reflect changes in the projected December 31, 2017 net book values. Additional information about the CSA is discussed under Coal Supply below and in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K.

During 2016, PNM revised its estimates of the December 31, 2017 projected book value of SJGS Units 2 and 3 and the other unrecoverable costs, which resulted in a net expense of $3.7 million, including a $4.5 million expense related to a refinement of the estimated liability for coal mine reclamation from the new coal mine reclamation arrangement. PNM recorded $0.8 million of such revision during the three months ended March 31, 2016, which is reflected in regulatory disallowances and restructuring costs on the Condensed Consolidated Statement of Earnings. In addition, PNMR Development recorded an expense of $0.6 million in the three months ended March 31, 2016 for costs it was obligated to reimburse the other SJGS participants under the restructuring arrangement, which is included in other deductions on the Condensed Consolidated Statement of Earnings. At March 31, 2017, the carrying value for PNM’s current ownership share of SJGS Units 2 and 3 is comprised of plant in service of $471.8 million and accumulated depreciation and amortization (including cost of removal) of $206.4 million for a net undepreciated book value of $265.4 million, offset by 50% (which equals $128.6 million) of the anticipated December 31, 2017 undepreciated net book value of SJGS Units 2 and 3 that will not be recovered, resulting in the net carrying value for SJGS Units 2 and 3 being $136.8 million at March 31, 2017.

On January 14, 2016, NEE filed a Notice of Appeal with the NM Supreme Court of the NMPRC’s December 16, 2015 order. On July 22, 2016, NEE filed a brief alleging that the NMPRC’s decision violated New Mexico statutes and NMPRC regulations because PNM did not adequately consider replacement resources other than those proposed by PNM, the NMPRC did not require PNM to adequately address and mitigate ratepayer risk, the NMPRC unlawfully shifted the burden of proof, and the NMPRC’s decision was arbitrary and capricious.  Answer briefs refuting NEE’s claims were filed on November 2, 2016 by PNM, the NMPRC, and certain intervenors. Reply briefs were filed by NEE on January 9, 2017 and the parties presented oral argument to the court on January 25, 2017. The court has not rendered a decision on the appeal and there is no required time frame for a decision. In addition, on March 31, 2016, NEE filed a complaint with the NMPRC against PNM regarding the financing provided by NM Capital to facilitate the sale of SJCC. The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. The NMPRC has taken no action on this matter. PNM cannot currently predict the outcome of these matters.

SJGS Ownership Restructuring Matters – As discussed in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Report on Form 10-K, SJGS currently is jointly owned by PNM and eight other entities. In connection with the

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)

proposed retirement of SJGS Units 2 and 3, some of the SJGS participants expressed a desire to exit their ownership in the plant. As a result, the SJGS participants negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items. The exiting participants currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4, but none of SJGS Units 1 and 2. PNM currently owns 50.0% of SJGS Units 1, 2, and 3 and 38.5% of SJGS Unit 4.

Following mediated negotiations, the SJGS participants executed the San Juan Project Restructuring Agreement (“RA”) on July 31, 2015. The RA provides the essential terms of restructured ownership and addresses other related matters, including that the exiting participants remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit. PNMR Development became a party to the RA and agreed to acquire a 65 MW ownership interest in SJGS Unit 4 on the exit date, which is anticipated to be December 31, 2017, but has obligations related to Unit 4 before then. On the exit date, PNM would acquire 132 MW and PNMR Development would acquire 65 MW of the capacity in SJGS Unit 4 from the exiting owners for no initial cost other than funding capital improvements, including the costs of installing SNCR and BDT equipment. PNMR Development’s share of the costs of installing SNCR and BDT equipment amounted to $7.6 million. PNMR currently anticipates that PNMR Development will transfer the rights and obligations related to the 65 MW to PNM prior to December 31, 2017 in order to facilitate dispatch of power from that capacity. As ordered by the NMPRC, PNM would treat the 65 MW as merchant utility plant that would be excluded from retail rates. Reflecting the additions of the 132 MW and 65 MW, PNM’s ownership share would be 77.3% in SJGS Unit 4 and an aggregate of 66.3% in SJGS Units 1 and 4.

The RA became effective contemporaneously with the effectiveness of the new CSA. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which as discussed in Coal Supply below, occurred at 11:59 PM on January 31, 2016. The RA sets forth the terms under which PNM acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and will supply coal to the exiting participants for the period from January 1, 2016 through December 31, 2017, which arrangement provides economic benefits that are being passed on to PNM’s customers through the FPPAC.

Other SJGS Matters – Although the RA results in an agreement among the SJGS participants enabling compliance with current CAA requirements, it is possible that the financial impact of climate change regulation or legislation, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant.

Four Corners

On August 6, 2012, EPA issued its Four Corners FIP with a final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to permanently close Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lbs/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.

PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $90.2 million, including amounts incurred through March 31, 2017 and PNM’s AFUDC. PNM is seeking recovery from its ratepayers of these costs in its NM 2016 Rate Case discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2016 Annual Report on Form 10-K and Note 12. PNM is unable to predict the ultimate outcome of this matter.

The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

52

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)

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

Carbon Dioxide Emissions

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

The Clean Power Plan establishes state-by-state targets for carbon emissions reduction and establishes deadlines for states to submit initial plans to EPA by September 6, 2016, with a potential two-year extension, and final plans by 2018. The September deadline has passed with no action and the 2018 deadline could be adjusted due to the stay of the Clean Power Plan issued by the US Supreme Court and pending litigation described below. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide, but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. State measures plans may only be used with mass-based goals and must include “backstop” federally enforceable standards that will become effective if the state measures fail to achieve the expected level of emission reductions.

On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan. On January 26, 2016, 29 states and state agencies filed a petition to the US Supreme Court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court issued a 5-4 decision granting the stay pending judicial review of the rule by the DC Circuit.  The decision means the Clean Power Plan is not in effect and states are not obliged to comply with its requirements. The DC Circuit heard oral arguments on September 27, 2016 in the case challenging the Clean Power Plan, but has not rendered a decision.

The proposed federal plan released concurrently with the Clean Power Plan is important to Four Corners and the Navajo Nation.  Since the Navajo Nation does not have primacy over its air quality program, the EPA would be the regulatory authority responsible for implementing the Clean Power Plan on the Navajo Nation, if the Clean Power Plan is sustained under the current administration.  In addition, the proposed rule recommends that EPA determine it is “necessary or appropriate” for EPA to regulate CO₂ emissions on the Navajo Nation.  The comment period for the proposed rule closed on January 21, 2016.  APS and PNM filed separate comments with EPA on EPA’s draft plan and model trading rules, advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA was to determine that it was not necessary or appropriate, the Clean Power Plan would not apply to the Navajo Nation, in which case, APS has indicated the Clean Power Plan would not have a material impact on Four Corners.  PNM is unable to predict the financial or operational impacts on Four Corners operations if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation.

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

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

53

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)

and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the New Source Performance Standards for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, (4) the Legal Memorandum supporting the Clean Power Plan, and (5) the New Source Performance Standards for Oil & Natural Gas Sector. 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 connection with its review, EPA filed a petition with the DC Circuit requesting that the court hold the consolidated cases challenging the Clean Power Plan in abeyance until 30 days after the conclusion of EPA’s review and any subsequent rulemaking. On April 28, 2017, the DC Circuit granted the motion to hold the consolidated cases in abeyance for 60 days, directed EPA to file status reports every 30 days, and ordered the parties to file supplemental briefs by May 15, 2017, addressing whether the cases should be remanded to EPA rather than held in abeyance.  The DC Circuit issued a similar order on the same day in connection with a motion filed by EPA to hold consolidated cases challenging the NSPS in abeyance.  EPA also signed a Federal Register notice announcing that EPA is initiating its review of the Clean Power Plan and providing advance notice of forthcoming rulemaking proceedings. The rulemaking process, if initiated, will require a period of public comment and will be subject to judicial review.

PNM’s review of the new CO₂ emission reductions standards is ongoing and the assessment of its impacts will depend on the litigation of the final rule and actions the Trump administration is taking through judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance, if any.

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO₂,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO₂ and the 24-hour SO₂ standard. New Mexico is in attainment for the 1-hour NOx NAAQS. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO₂ NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO₂ sources to identify maximum 1-hour SO₂ concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO₂ sources through ambient monitoring or modeling. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO₂ NAAQS.  On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposes deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO₂ emissions. The settlement results from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree requires the following: (1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO₂ in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; (2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule.  SJGS and Four Corners SO₂ emissions are below the tonnages set forth in (1) above. EPA regions sent letters to state environmental agencies explaining how EPA plans to implement the consent decree.  The letters outline the schedule that EPA expects states to follow in moving forward with new SO₂ non-attainment designations. NMED did not receive a letter.

On August 11, 2015, EPA released the Data Requirements Rule for SO₂, telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO₂ NAAQS.  On June 3, 2016, NMED notified PNM that air quality modeling results indicated that SJGS was in compliance with the standard. In January 2017, NMED submitted their formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO₂ standard. In July of each year, NMED will submit an annual report to EPA documenting annual SO₂ emissions from SJGS and the associated compliance status.

On May 14, 2015, PNM received an amendment to its NSR air permit for SJGS, which reflects the revised state implementation plan for regional haze BART and requires the installation of SNCRs as described above. The revised permit also requires the reduction of 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 will

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help SJGS meet the NAAQS for these constituents. The BDT equipment modifications were installed at the same time as the SNCRs, in order to most efficiently and cost effectively conduct construction activities at SJGS. See Regional Haze – SJGS above.

In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 60-70 parts per billion (“ppb”). On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 ppb to 70 ppb. With ozone standards becoming more stringent, fossil-fueled generation units will come under increasing pressure to reduce emissions of NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas.

On November 10, 2015, EPA proposed a rule revising its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data are affected by events outside an area’s control. The proposed rule is timely in light of the new more stringent ozone NAAQS final rule since western states like New Mexico and Arizona are particularly subject to elevated background ozone transport from natural local sources such as wildfires, and transported via winds from distant sources, such as the stratosphere or another region or country.

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

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

PNM does not believe there will be material impacts to its facilities as a result of NMED’s nonattainment designation of the small area within Dona Ana County, but must wait on EPA’s ultimate approval, which should occur by October 1, 2017. Until EPA approves attainment designations for the Navajo Nation and releases a proposal to implement the revised ozone NAAQS, APS is unable to predict what impact the adoption of these standards may have on Four Corners. PNM cannot predict the outcome of this matter.

WEG v. OSM NEPA Lawsuit

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

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litigation will be administratively closed. If OSM does not complete the EIS within the time frame provided, the court will order immediate vacatur of the mining plan at issue.  The scope of the EIS will be determined through a public process and is expected to include cumulative and indirect effects of surrounding sources. 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 the EIS will also analyze the effects of coal combustion at SJGS. PNM cannot currently predict the outcome of this matter.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation’s authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the court granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.

Cooling Water Intake Structures

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

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

The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is in discussion with EPA regarding this issue. However, PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS. APS is currently in discussions with EPA Region 9, the NPDES permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. PNM does not expect such costs to be material.

Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants.  EPA’s proposal offered numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning waste operations.  All proposed alternatives establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. Requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits.

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

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

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

PNM facilities are not expected to be significantly impacted if the challenge to the rule is unsuccessful and the compliance deadlines remain in effect. Based upon the current requirements of the Steam Electric Effluent Guidelines Rule, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. Until a draft NPDES permit is proposed for Four Corners, APS is uncertain what will be required to comply with the finalized effluent limitations.  PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. 

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED also has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. Results of tests conducted by NMED in April 2012 and April 2013 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property.  This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels, and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. However, it is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels.  Therefore, PNM has agreed to monitor nitrate levels in a limited number of wells under the terms of the renewed discharge permit for the former generating station.  PNM is unable to predict the outcome of these matters.

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Effective December 22, 2015, PNM and NMED entered into a memorandum of understanding to address changing groundwater quality conditions at the site. Under the memorandum, PNM will continue hydrocarbon investigation of the site under the supervision of NMED and qualified costs of the work will be eligible for payment through the New Mexico Corrective Action Fund (“CAF”), which is administered by the NMED Petroleum Storage Tank Bureau. Among other things, money in the CAF is available to NMED to make payments to or on behalf of owners and operators for corrective action taken in accordance with statutory and regulatory requirements to investigate, minimize, eliminate, or clean up a release. PNM’s work plan and cost estimates for specific groundwater investigation tasks were approved by the Petroleum Storage Tank Bureau. PNM submitted a monitoring plan consisting of a compilation of the data associated with the recent monitoring activities conducted under the CAF to NMED on October 3, 2016. Following NMED’s review of the data, PNM and NMED will develop plans for the next phase of work under the CAF.

Coal Combustion Byproducts Waste Disposal

CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments or landfills. The NMMMD currently regulates placement of ash, which is generated from coal combustion at SJGS, in the San Juan mine with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners.  Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office.

In June 2010, EPA published a proposed rule that included two options for waste designation of coal ash. One option was to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option was to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. 

On December 19, 2014, EPA issued its coal ash rule, including a non-hazardous waste determination for coal ash. Coal ash will be regulated as a solid waste under Subtitle D of RCRA. The rule sets minimum criteria for existing and new CCB landfills and existing and new CCB surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria; groundwater monitoring and corrective action; closure requirements and post closure care; and recordkeeping, notification, and internet posting requirements.

Because the rule is promulgated under Subtitle D, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non-compliance with the new requirements. EPA published the final CCB rule in the Federal Register on April 17, 2015, with an effective date of October 19, 2015. Based upon the requirements of the final rule, PNM conducted a CCB assessment at SJGS and made minor modifications at the plant to ensure that there are no facilities which would be considered impoundments or landfills under the rule. PNM does not expect it to have a material impact on operations, financial position, or cash flows.

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

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

On December 16, 2016, the Water Infrastructure Improvements for the Nation Act (the “WIIN Act”) was signed into law to address critical water infrastructure needs in the United States. The WIIN Act contains a number of provisions requiring EPA

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to modify the self-implementing provisions of the current CCB rules under Subtitle D. Among other things, the WIIN Act provides for the establishment of state and EPA permit programs for CCBs, provides flexibility for states to incorporate the EPA final rule for CCBs or develop other criteria that are at least as protective as the EPA’s final rule, and requires EPA to approve state permit programs within 180 days of submission by the state for approval. As a result, the CCB rule is no longer self-implementing and there will either be a state or federal permit program. Subject to Congressional appropriated funding, EPA will implement the permit program in states that choose not to implement a program. Until permit programs are in effect, EPA has authority to directly enforce the self-implementing CCB rule. For facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation where Four Corners is located, EPA is required to develop a federal permit program regardless of appropriated funds. EPA has yet to undertake rulemaking proceedings to implement the CCB provisions of the WIIN Act. There is no time line for establishing either state or federal permitting programs.

The December 2014 CCB rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCB rules. The CCB rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in 2017 and will likely be influenced by EPA’s rule. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows. PNM would seek recovery from its ratepayers of all CCB costs that are ultimately incurred.

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are supplied by SJCC. SJCC holds certain federal, state, and private coal leases. Through January 31, 2016, SJCC was a wholly owned subsidiary of BHP and supplied processed coal for operation of SJGS under an underground coal sales agreement (“UG-CSA”) that was to expire on December 31, 2017. In addition to coal delivered to meet the current needs of SJGS, PNM prepaid SJCC for certain coal mined but not yet delivered to the plant site. At March 31, 2017 and December 31, 2016, prepayments for coal (including amounts purchased from the existing SJGS participants discussed below), which are included in other current assets, amounted to $43.0 million and $48.7 million. Additional information concerning the coal supply for SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS after the expiration of the UG-CSA. On July 1, 2015, PNM and Westmoreland Coal Company (“Westmoreland”) entered into a new coal supply agreement (“CSA”), pursuant to which Westmoreland will supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland will provide CCB disposal and mine reclamation services. Contemporaneous with the entry into the coal-related agreements, Westmoreland entered into a stock purchase agreement (the “Stock Purchase Agreement”) on July 1, 2015 to acquire all of the capital stock of SJCC. In addition, PNM, Tucson, SJCC, and SJCC’s owner entered into an agreement to terminate the existing UG-CSA upon the effective date of the new CSA.

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

Pricing under the CSA is primarily fixed, adjusted to reflect general inflation. The pricing structure takes into account that SJCC has been paid for coal mined but not delivered, as discussed above. PNM has the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. In order to extend, PNM must give written notice of that intent by July 1, 2018 and the parties must agree to the terms of the extension by January 1, 2019. The RA sets forth terms under which PNM acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and will supply coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and to the SJGS remaining participants over

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the term of the CSA. Coal costs under the CSA are significantly less than under the previous arrangement with SJCC. Since substantially all of PNM’s coal costs are passed through the FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners are passed through to PNM’s customers.

In support of the closing under the Stock Purchase Agreement and to facilitate PNM customer savings, NM Capital, a wholly owned subsidiary of PNMR, provided funding of $125.0 million (the “Westmoreland Loan”) to Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland, to finance the purchase price of the stock of SJCC (including an insignificant affiliate) under the Stock Purchase Agreement. NM Capital was able to provide the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent. The BTMU Term Loan Agreement became effective as of February 1, 2016, has a maturity date of February 1, 2021, and bears interest at a rate based on LIBOR plus a customary spread. In connection with the BTMU Term Loan Agreement, PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. The balance outstanding under the BTMU Term Loan Agreement was $82.8 million at March 31, 2017.

The Westmoreland Loan is a $125.0 million loan agreement among NM Capital, as lender, WSJ, as borrower, SJCC and its affiliate, as guarantors, BTMU, as administrative agent, and MUFG Union Bank, N.A., as depository bank. The Westmoreland Loan became effective as of February 1, 2016, and has a maturity date of February 1, 2021. The interest rate on the Westmoreland Loan escalates over time and was initially a rate of 7.25% plus LIBOR. Such rate is 9.25% plus LIBOR for the period from February 1, 2017 through January 31, 2018. The Westmoreland Loan has been structured to encourage prepayments and early retirement of the debt. WSJ must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. In addition, the Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. At March 31, 2017, the amount outstanding under the Westmoreland Loan was $85.4 million. The next principal payment of $9.6 million plus interest of $2.2 million is due on May 2, 2017. As of April 24, 2017, $11.8 million was held in a SJCC restricted bank account that is to be used solely to service the Westmoreland Loan. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC and its affiliate. The Westmoreland Loan also includes customary representations and warranties, covenants, and events of default. There are no prepayment penalties.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds of $118.7 million with the NMMMD. In order to facilitate the posting of reclamation bonds by sureties on behalf of SJCC, PNMR entered into separate letter of credit arrangements with a bank under which letters of credit aggregating $30.3 million have been issued.

Four Corners

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to NTEC, an entity owned by the Navajo Nation, and a new coal supply contract for Four Corners, beginning in July 2016 and expiring in 2031, was entered into with NTEC. The BHP subsidiary was retained as the mine manager and operator through December 2016. Bisti Fuels Company, LLC, a subsidiary of The North American Coal Corporation, took over management and operation of the mine effective January 1, 2017. The average coal price per MMBTU under the new contract was approximately 48% higher in the second half of 2016 than in the second half of 2015. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

Coal Mine Reclamation

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

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(Unaudited)

in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. As discussed under Coal Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant.

In 2015, PNM updated its final reclamation costs estimates to reflect the terms of the new reclamation services agreement with Westmoreland, discussed above, and changes resulting from the approval of the 2015 SJCC Mine Permit Plan. The 2015 reclamation cost estimate reflects that the scope and pricing structure of the reclamation service agreement with Westmoreland would significantly increase reclamation costs. In addition, design plan changes, updated regulatory expectations, and common mine reclamation practices incorporated into the 2015 SJCC Mine Permit reflect an increase in the 2015 reclamation cost estimate. The impacts of these increases, amounting to $16.5 million, were recorded at December 31, 2015.

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

Based on the 2016 estimates and PNM’s current ownership share of SJGS, PNM’s remaining payments as of March 31, 2017 for mine reclamation, in future dollars, are estimated to be $102.0 million for the surface mines at both SJGS and Four Corners and $127.8 million for the underground mine at SJGS. At March 31, 2017 and December 31, 2016, liabilities, in current dollars, of $41.5 million and $41.0 million for surface mine reclamation and $14.0 million and $14.0 million for underground mine reclamation were recorded in other deferred credits.

Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation costs associated with the supply of coal from the San Juan mine. The SJGS owners entered into a reclamation trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the UG-CSA. As part of the restructuring of SJGS ownership (see SJGS Ownership Restructuring Matters above), the SJGS owners and PNMR Development negotiated the terms of an amended agreement to fund post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable reclamation trust, and periodically deposit funds into the reclamation trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels. Based on PNM’s reclamation trust fund balance at March 31, 2017, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $6.9 million in 2017, $8.3 million in 2018, and $8.7 million in 2019.

Under the coal supply agreement for Four Corners, which became effective on July 7, 2016, PNM is required to fund its ownership share of estimated final reclamation costs in thirteen annual installments, beginning on August 1, 2016, into an irrevocable escrow account solely dedicated to the final reclamation cost of the surface mine at Four Corners. PNM’s anticipated funding level is $2.0 million, $2.1 million, and $2.1 million in 2017, 2018, and 2019.

PNM collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from retail customers for final reclamation of the surface mines at $100.0 million. Previously, PNM recorded a regulatory asset for the $100.0 million and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. Regulatory determinations made by the NMPRC may also affect the impact on PNM. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

As discussed in Note 12, PNM released a draft of its 2017 IRP on April 20, 2017. The preliminary conclusions contained in the 2017 IRP indicate that it would be cost beneficial to PNM’s customers for SJGS to be shutdown in 2022 and for PNM to exit its ownership interest in Four Corners in 2031. If the final 2017 IRP contains those same conclusions and if the NMPRC orders the abandonment of those facilities, PNM would be required to remeasure its liability for coal mine reclamation to reflect

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(Unaudited)

that reclamation activities would occur sooner than currently anticipated. The remeasurement would likely result in an increase in PNM’s liability under GAAP. PNM would record a regulatory asset for amounts recoverable from ratepayers under existing or future orders of the NMPRC and amounts not recoverable would be expensed. PNM cannot predict what the final 2017 IRP will conclude or what actions the NMPRC might take.

Continuous Highwall Mining Royalty Rate

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

SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS.  In March 2001, SJCC learned that the DOI Minerals Management Service (“MMS”) disagreed with the application of the underground royalty rate to CHM.  In August 2006, SJCC and MMS entered into an agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal.  The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed.  PNM’s share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM’s FPPAC. PNM is unable to predict the outcome of this matter.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with this act, the PVNGS participants are insured against public liability exposure for a nuclear incident up to $13.4 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers. The remaining $13.0 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential retrospective premium assessment per incident for all three units is $38.9 million, with a maximum annual payment limitation of $5.8 million, to be adjusted periodically for inflation.

The PVNGS participants maintain insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). A sublimit of $2.25 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium 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

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(Unaudited)

other water users in the San Juan basin. The agreement to share shortages in 2017 through 2020 has been negotiated and awaits endorsement by the parties and the New Mexico State Engineer.

In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for 40 years.

PVNGS Water Supply Litigation

In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows.

San Juan River Adjudication

In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, former President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo Nation’s water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees.  The court issued an order in August 2013 finding that no evidentiary hearing was warranted in the Navajo Nation proceeding and, on November 1, 2013, issued a Partial Final Judgment and Decree of the Water Rights of the Navajo Nation approving the proposed settlement with the Navajo Nation. Several parties filed a joint motion for a new trial, which was denied by the court. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM has entered its appearance in the appellate case. The issues have been fully briefed and the matter is pending with the New Mexico Court of Appeals.

PNM is participating in this proceeding since PNM’s water rights in the San Juan Basin may be affected by the rights recognized in the settlement agreement as being owned by the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin. PNM is unable to predict the ultimate outcome of this matter or estimate the amount or range of potential loss and cannot determine the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. Final resolution of the case cannot be expected for several years. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

Rights-of-Way Matter

On January 28, 2014, the County Commission of Bernalillo County, New Mexico passed an ordinance requiring utilities to enter into a use agreement and pay a yet-to-be-determined fee as a condition to installing, maintaining, and operating facilities on county rights-of-way. The fee is purported to compensate the county for costs of administering and maintaining the rights-of-way, as well as for capital improvements. On February 27, 2014, PNM and other utilities filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. The court denied the utilities’ motion for judgment. The court further granted the County’s motion to dismiss the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. In subsequent briefing in federal court, the County filed a motion for judgment on one of the utilities’ claims, which was granted by the court, leaving a claim regarding telecommunications service as the remaining federal claim. On January 4, 2016, the utilities filed an Application for Interlocutory Appeal from the state court, which was denied. On March 28, 2017, the utilities filed a writ of certiorari with the NM Supreme Court, which was denied. The matter will proceed in New Mexico District Court. The utilities and Bernalillo County reached a standstill agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement. If the challenges to

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(Unaudited)

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

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

In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice.  On April 2, 2014, the allottees’ appeal was dismissed with prejudice. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments.  On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested.  The letter indicated that the renewals were not approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. On July 13, 2015, PNM filed a condemnation action in the United States District Court for the District of New Mexico regarding the approximately 15.49 acres of land at issue. On December 1, 2015, the court ruled that PNM could not condemn two of the five allotments at issue based on the Navajo Nation’s fractional interest in the land. PNM’s motion for reconsideration of this ruling was denied. On March 31, 2016, the Tenth Circuit granted PNM’s petition to appeal the December 1, 2015 ruling. On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. Both matters have been consolidated and are stayed while PNM pursues its appeal before the Tenth Circuit. On June 27, 2016, PNM filed its opening brief in the Tenth Circuit. Amicus briefs were filed in support of PNM’s position. On October 5, 2016, the United States, the Navajo Nation, and individual allottees filed their response briefs. After the response briefs were filed, other entities requested leave to file amicus briefs addressing arguments raised in the United States’ response brief. Oral argument before the Tenth Circuit was heard on January 17, 2017.

PNM cannot predict the outcome of these matters.

(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 2016 Annual Reports on Form 10-K.

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(Unaudited)

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 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. On March 2, 2016, the NMPRC required PNM to file supplemental testimony regarding the treatment of renewable energy in PNM’s FPPAC. See Renewable Portfolio Standard below. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016, pursuant to the terms of the initial sales-leaseback transactions (Note 6). A subsequent public hearing was held in June 2016. After the June hearing, PNM and other parties were ordered to file supplemental briefs and to provide final recommended revenue requirements that incorporated fuel savings that PNM implemented effective January 1, 2016 from PNM’s SJGS coal supply agreement (“CSA”).  PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current CSA (Note 11), which also reduced the request for base non-fuel related revenues by $0.2 million to $121.5 million.

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

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

• Disallowing recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying three leases of portions of PVNGS Unit 2 (Note 6); the RD proposed that power from the previously leased assets, aggregating 64.1 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expenses (other than property taxes, which were $0.8 million per year at that time), but the customers would not bear any capital or depreciation costs other than those related to improvements made after the date of the original leases

• Disallowing recovery from retail customers of the rent expense, which aggregates $18.1 million per year, under the four leases of capacity in PVNGS Unit 1 that were extended for eight years beginning January 15, 2015 and the one lease of capacity in PVNGS Unit 2 that was extended for eight years beginning January 15, 2016 (Note 6) and related property taxes, which were $1.5 million per year at that time; the RD proposed that power from the leased assets, aggregating 114.6 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expense, except that customers would not bear rental costs or property taxes

• Disallowing recovery of the costs of converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS, (Note 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 RD recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. The RD also proposed that all fuel costs be removed from base rates and be recovered through the FPPAC. The RD would credit retail customers with 100% of the New Mexico jurisdictional portion of revenues from refined coal (a third-party pre-treatment process) at SJGS. In addition, the RD would remove recovery of the costs of power

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(Unaudited)

obtained from New Mexico Wind from the FPPAC and include recovery of those costs through PNM’s renewable energy rider discussed below. The RD recommended continuation of the renewable energy rider and certain aspects of PNM’s proposals regarding rate design, but would not approve certain other rate design proposals or PNM’s request for a revenue decoupling pilot program. The RD proposed approving PNM’s proposals for revised depreciation rates (with one exception), the inclusion of CWIP in rate base, and ratemaking treatment of the prepaid pension asset. The RD did not preclude PNM from supporting the prudence of the PVNGS purchases and lease renewals in its next general rate case and seeking recovery of those costs. PNM disagreed with many of the key conclusions reached by the Hearing Examiner in the RD and filed exceptions to defend its prudent utility investments. Other parties also filed exceptions to the RD.  

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• The final rate design

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

NEE subsequently filed a motion for a partial stay of the order at the NM Supreme Court. This motion was denied. The NM Supreme Court stated that the court’s intent was to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits. Otherwise, the court has taken no action with respect to the appeals. On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule is anticipated to be completed by June 28, 2017. Although appeals of regulatory actions of the NMPRC have a priority at the NM Supreme Court under New Mexico law, there is no required time frame for the court to act on the appeals.

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(Unaudited)

GAAP requires that a loss is to be recognized when it is probable that a loss has been incurred and the amount of loss can be reasonably estimated. When there is a range of the amount of the probable loss, the minimum amount of the range is to be accrued unless an amount within the range is a better estimate than any other amount. PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicates it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the issues, those issues would be remanded back to the NMPRC for further action. PNM estimates that it will take a minimum of 15 months, from the date PNM filed its appeal, for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order will remain in effect. PNM has concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case; that the minimum amount of loss is 15 months of capital cost recovery that the order disallowed for its investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT; and that no amount within the range of possible loss is a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million in September 2016 for the capital costs that will not be covered during that 15 month appeal period. In addition, PNM recorded a pre-tax regulatory disallowance for $4.5 million of costs recorded as regulatory assets and deferred charges (which the order disallowed and which PNM did not challenge in its appeal) since PNM can no longer assert that those assets are probable of being recovered through the ratemaking process. Additional losses will be recorded if the currently estimated 15 month time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is extended. The NMPRC’s order approved PNM’s request to record a regulatory asset to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from an extension of the income tax provision for fifty percent bonus depreciation. The impact, net of federal income taxes, amounts to $2.1 million, which was reflected as a reduction of income tax expense in September 2016.

PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurred and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is reasonably possible that its appeals will be successful, it cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record further pre-tax losses related to the capitalized costs for any unsuccessful issues. The impacts of not recovering future contributions for decommissioning would be recorded in future periods. The amounts of any such losses to be recorded would depend on the ultimate outcome of the appeal and NMPRC process, as well as the actual amounts reflected on PNM books at the time of the resolution. However, based on the book values recorded by PNM as of March 31, 2017, such losses could include:

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

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

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

Also, PNM has evaluated the accounting consequences of the issues that are being appealed by the cross-appellants. Although PNM does not believe the issues raised in the cross-appeals have substantial merit, PNM is unable to predict what decision the NM Supreme Court will reach. PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, if the Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $154.9 million (which amount includes $76.9 million that is the subject of PNM’s appeal discussed above) at March 31, 2017, after considering the loss recorded in 2016. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and prepaid pension asset in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have financial impact to PNM.

PNM is unable to predict the outcome of this matter.

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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. Key aspects of PNM’s request are:

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

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

• ROE of 10.125%

• Drivers of revenue deficiency

◦ Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (Note 11)

◦ Infrastructure investments, including environmental upgrades at Four Corners

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

◦ Updates in the FERC/retail jurisdictional allocations

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

◦ Increased customer and demand charges

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

The NMPRC scheduled a public hearing to begin on June 5, 2017, ordered that a settlement conference should be held, and that any resulting stipulation should be filed by March 27, 2017. Settlement discussions have been held, but no agreements were reached by March 27, 2017. PNM and several intervenors filed an unopposed motion with the NMPRC to extend by one month the procedural schedule, including the date for filing a stipulation. On April 12, 2017, the NMPRC issued an order modifying the procedural schedule to allow for additional settlement discussion. Under the revised schedule, any settlement stipulation was to be filed by April 27, 2017 and the public hearing would begin on July 10, 2017. On April 27, 2017, PNM and several intervenors filed a motion with the NMPRC to extend the deadline for filing a stipulation to May 5, 2017. The motion is subject to approval by the Hearing Examiner. Upon filing, a settlement would require the approval of the NMPRC in order to take effect. PNM cannot predict the outcome of this matter.

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 Staff on the one hand, and the utilities on the other.” The order posed the following questions: whether a standardized method (“DCF”) 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. A procedural schedule has been established that includes initial comments on July 10, 2017 and a public workshop on August 9, 2017. PNM cannot predict the outcome of this proceeding.

Renewable Portfolio Standard

The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. PNM files annual renewable energy procurement plans for approval by the NMPRC. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are minimums of 30% wind, 20% solar, 3% distributed generation, and 5% other.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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. 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:

• 107 MW of PNM-owned solar PV facilities, including 40 MW constructed in 2015 that were identified as a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11) and are being recovered in the base rates provided in the NM 2015 Rate Case discussed above rather than through PNM’s renewable energy rider; and an additional procurement of 1.5 MW of PNM-owned solar PV facilities to supply the energy sold under PNM’s voluntary renewable energy tariff

• A PPA through 2027 for the output of New Mexico Wind, having an aggregate capacity of 204 MW and a PPA through 2035 for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW

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

• Solar distributed generation, aggregating 66.8 MW at March 31, 2017, owned by customers or third parties from whom PNM purchases any net excess output and RECs

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

PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan met RPS and diversity requirements within the RCT in 2016 and 2017 using existing resources and did not propose any significant new procurements. The NMPRC approved the plan in November 2015, and, after granting a rehearing motion to consider issues regarding the rate treatment of certain customers eligible for a cap on, or an exemption from, RPS procurement, the NMPRC again approved the plan in an order issued on February 3, 2016. The NMPRC deferred issues related to capped and exempt customers to PNM’s NM 2015 Rate Case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The NM 2015 Rate Case and show cause proceeding were to examine whether PNM miscalculated the FPPAC factor and base fuel costs in its treatment of renewable energy costs and application of the renewable procurement cost caps and exemptions. The show cause proceeding was stayed pending the outcome of the NM 2015 Rate Case. The September 28, 2016 order in the NM 2015 Rate Case directed that the cost of New Mexico Wind be recovered through PNM’s renewable rider, rather than the FPPAC, and ordered certain other modifications regarding the accounting for renewable energy in PNM’s FPPAC. These modifications do not affect the amount of fuel and purchased power or renewable costs that PNM will collect. No action has been taken in the show cause proceeding and PNM cannot predict its outcome.

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

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In PNM’s NM 2015 Rate Case, the NMPRC authorized continuation of the renewable rider. PNM recorded revenues from the rider of $11.0 million and $8.4 million in the three months ended March 31, 2017 and 2016.

In its 2016 renewable energy procurement plan case, PNM proposed to collect $42.4 million in 2016. The 2016 rider adjustment was approved as part of the order issued February 3, 2016 approving the 2016 renewable energy plan. In its 2017 renewable energy procurement plan, PNM proposed to collect $50.0 million through the rider in 2017. The increase, as compared with the amount the NMPRC approved for recovery through the rider in 2016, was due to recovering the costs of energy from New Mexico Wind through the rider, rather than through the FPPAC in compliance with the NMPRC’s order in PNM’s NM 2015

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Rate Case. The 2017 rider adjustment was approved in the November 23, 2016 order that approved the 2017 renewable energy plan. On February 28, 2017, PNM filed a reconciliation of 2017 revenue requirement and proposed a revision to the rider that would recover $42.7 million during 2017.

Under the renewable rider, if PNM’s earned rate of return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM is required to refund the excess to customers during May through December of the following year. PNM’s annual compliance filings with the NMPRC show that its rate of return on jurisdictional equity did not exceed the limitation through 2016.

Energy Efficiency and Load Management

Program Costs and Incentives

Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. The act sets an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s costs to implement approved programs are recovered through a rate rider.

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

On April 14, 2017, PNM filed an application for energy efficiency and load management programs to be offered in 2018. The proposed program portfolio consists of a continuation of the ten programs approved in the 2016 application with a total budget of $25.1 million. The application also seeks approval of a sliding scale incentive with a base incentive of $1.9 million if PNM is able to achieve saving of 53 GWh in 2018. PNM projects it would earn an incentive of $2.1 million based on targeted savings of 70 GWh. The actual incentive would be based on actual savings achieved. The application also requests a variance if the NMPRC approves a pending rulemaking that would reduce the frequency of energy efficiency applications to every other year so that PNM would not have to file its next energy efficiency application until 2019. PNM proposes to continue the same ten programs and a similar incentive mechanism in 2019, with a proposed budget of $28.2 million and a base level incentive of $2.1 million. PNM is unable to predict the outcome of this proceeding.

Energy Efficiency Rulemaking

In July 2012, the NMPRC opened an energy efficiency rulemaking docket to potentially address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

On January 25, 2017, the NMPRC opened another energy efficiency rulemaking docket to consider whether applications for approval of energy efficiency and load management programs should be filed every two years rather than annually. Written comments were filed in the rulemaking docket, and a public comment hearing was held on March 31, 2017. PNM is unable to 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.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2014 IRP

PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term resource needs with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the then pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they asserted that the IRP did not conform to the NMPRC’s IRP rule. Certain parties also asked that further proceedings on the IRP be held in abeyance until the conclusion of the SJGS abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that docketed a case to determine whether the IRP complied with applicable NMPRC rules. The order also held the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3. The order regarding PNM’s application to abandon SJGS Units 2 and 3 described in Note 11 states that the NMPRC will issue a Notice of Proposed Dismissal in the 2014 IRP docket. On May 4, 2016, the NMPRC issued the Notice of Proposed Dismissal, stating that the docket 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 IRP in abeyance or to dismiss those protests without prejudice. PNM responded on June 13, 2016 and requested that the NMPRC dismiss the case with prejudice. The NMPRC has not yet acted on its Notice of Proposed Dismissal or the request filed on May 31, 2016. PNM cannot predict the outcome of this matter.

2017 IRP

The 2017 IRP will address a 20-year planning period, from 2017 through 2036, and will include an action plan describing PNM’s plan to implement the 2017 IRP in the four-year period following its filing. PNM held its initial public advisory meeting on the 2017 IRP on June 30, 2016. The public advisory process is proceeding in three phases: in the first, PNM will build assumptions and discuss scenarios and sensitivities; in the second, PNM will discuss its analysis; and in the third, PNM will discuss its draft IRP with the public advisory participants. PNM intends to file its 2017 IRP by July 3, 2017, within the time limit prescribed by NMPRC rule. The NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 11 requires PNM to make a filing in 2018 to determine the extent to which SJGS Units 1 and 4 should continue serving PNM’s retail customers’ needs after June 30, 2022. To facilitate the 2018 filing, PNM is developing two resource portfolios in the 2017 IRP, one with SJGS continuing beyond mid-2022 and one where it is shut down. On March 17, 2017, PNM announced that preliminary results of its analysis indicate that retirement of SJGS in 2022 could be cost-effective for customers.

On April 20, 2017, PNM released a draft of the 2017 IRP. Key findings in that draft 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 built from Eastern New Mexico to PNM’s service territory

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

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

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

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

• PNM should pursue securitization legislation to provide additional customer cost savings and provide funds for replacement resources

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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)

The draft of the 2017 IRP sets forth the results of the IRP process to date. Additional input through a continuing public advisory process could lead to further analysis of the resource mix, which could result in revisions from the draft plan. PNM must file the final IRP by July 3, 2017. PNM cannot predict the ultimate outcome of the 2017 IRP process or whether the NMPRC will approve subsequent filings that would encompass actions to implement the conclusions of the 2017 IRP.

San Juan Generating Station Units 2 and 3 Retirement

On December 16, 2015, the NMPRC issued an order approving PNM’s retirement of SJGS Units 2 and 3 on December 31, 2017. On January 14, 2016, NEE filed an appeal of the order with the NM Supreme Court. Additional information concerning the NMPRC filing and related proceedings is set forth in Note 11.

Application for Certificate of Convenience and Necessity

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

Advanced Metering Infrastructure Application

On February 26, 2016, PNM filed an application with the NMPRC requesting approval of a project to replace its existing customer metering equipment with Advanced Metering Infrastructure (“AMI”). The application also asks the NMPRC to authorize the recovery of the cost of the project, up to $87.2 million, in future ratemaking proceedings, as well as to approve the recovery of the remaining undepreciated investment in existing metering equipment estimated to be approximately $33 million at the date of implementation and the costs of customer education and severances for affected employees. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. On August 5, 2016, PNM filed a motion to suspend its AMI application so that it could evaluate the effect of the order in the NM 2015 Rate Case. The NMPRC approved this motion. On November 22, 2016, PNM filed a motion to lift the suspension and establish a new procedural schedule. In December 2016, the Hearing Examiner issued an order lifting the suspension and issued a new procedural schedule. Hearings in this matter were held in February and March 2017. The Hearing Examiner has required submission of additional testimony related to the meter contractor’s compliance with construction industries licensure requirements and may schedule a further hearing. PNM cannot predict the outcome of this matter.

Facebook Data Center Project

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

• Two new electric service rates

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

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

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

The customer’s service requirements include the acquisition by PNM of a sufficient amount of new renewable energy resources and RECs to match the energy and capacity requirements of the data center. PNM’s initial procurement will be through a PPA with PNMR Development for the energy production from 30 MW of new solar capacity that PNMR Development will

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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)

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

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

Hazard Sharing Agreement

On June 1, 2016, PNM and Tri-State entered into a one-year hazard sharing agreement, which expires on May 31, 2017.  Under the agreement, each party will sell the other party 100 MW of capacity and energy on a unit contingent basis, from each party’s designated primary resources, which is SJGS Unit 4 for PNM and Springerville Generating Station Unit 3 for Tri-State.  Both purchases and sales are made at the same market index price.  In 2016, PNM sold 482,342 MWh for $12.8 million and purchased 484,632 MWh for $12.9 million under the agreement. In the three months ended March 31, 2017, PNM sold 213,533 MWh for $4.8 million and purchased 205,156 MWh for $4.6 million under the agreement. The agreement serves to reduce the magnitude of each party’s single largest generating hazard and assists in enhancing the reliability and efficiency of their respective operations. PNM and Tri-State have entered into an additional agreement, under substantially identical terms, for a term of five years beginning June 1, 2017, subject to NMPRC approval. NMPRC approval was not required for the one-year agreement, but is required for the five-year agreement. On November 30, 2016, PNM filed an application with the NMPRC for approval of the five-year agreement. A public hearing on PNM’s request was held on March 23, 2017. On April 26, 2017, the Hearing Examiner in the case issued a recommended decision that would approve PNM’s application. PNM cannot predict the outcome of this matter.

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

As discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, NEC filed a petition on April 8, 2015 for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under its PSA with PNM. Following proceedings before a settlement judge, PNM and NEC entered into, and filed with FERC, a settlement agreement on October 29, 2015 that includes certain amendments to the PSA and related contracts on file with FERC. FERC approved the settlement on January 21, 2016. Under the settlement agreement, PNM served all of NEC’s load in 2016 at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC also paid certain third-party transmission costs that it only partially paid previously. The PSA and related transmission agreements terminated on December 31, 2016. In 2017, PNM is serving 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. Amounts billed to NEC were $1.1 million and $5.4 million in the three months ended March 31, 2017 and 2016. PNM’s NM 2016 Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve NEC.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011. TNMP completed its mass deployment in 2016 and has installed more than 242,000 advanced meters.

The PUCT adopted a rule creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service is to be borne by opt-out customers through an initial fee and ongoing monthly charge. As approved by the PUCT, TNMP is recovering $0.2 million in costs through

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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)

initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million through a $36.78 monthly fee. These amounts presume up to 1,081 consumers will elect the non-standard meter service, but TNMP has the right to adjust the fees if the number of anticipated consumers differs from that estimate. As of April 24, 2017, 103 consumers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

Transmission Cost of Service Rates

TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s recent interim transmission cost rate increases:

Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 10, 2015	$	7.0	$	1.4
March 23, 2016	25.8		4.3
September 8, 2016	9.5		1.8
March 14, 2017	30.2		4.8

On March 23, 2017, the PUCT staff filed proposed amendments to the interim TCOS filing rule. If approved, the amendments could reduce the frequency of such filings to once per year. The amendments could also reduce the amount recovered by requiring that changes in accumulated deferred income taxes be considered and would preclude filings by utilities earning more than their authorized rate of return using weather-normalized data. The PUCT has not yet approved the amendments for publication. Initial comments on the proposed rule will be due 30 days after publication. TNMP cannot predict the outcome of this matter.

Periodic Distribution Rate Adjustment

PUCT rules permit interim rate adjustments to reflect changes in investments in distribution assets. Distribution utilities may file for a periodic rate adjustment between April 1 and April 8 of each year as long as the electric utility is not earning more than its authorized rate of return using weather-normalized data. However, TNMP has not made a filing to adjust rates for additional investments in distribution assets. In connection with TNMP’s deployment of its advance meter system discussed above, TNMP committed to file a general rate case no later than September 1, 2018. TNMP has also committed that it would not file a request for an increase in rates to reflect changes in investments in distribution assets until after the 2018 general rate case.

Competition Transition Charge Compliance Filing

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

(13) Income Taxes

In 2013, New Mexico House Bill 641 reduced the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction is being phased-in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment, which was in the year ended December 31, 2013. At that time, the portion of the adjustment related to PNM’s regulated activities

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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)

was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. In addition, the portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax expense. Changes in the estimated timing of reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2017 and 2016, PNM’s regulatory liability was reduced by $4.8 million and $7.1 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: reduced by $0.1 million in the three months ended March 31, 2017, increasing income tax expense by less than $0.1 million for PNM and $0.1 million for the Corporate and Other segment; and decreased by $0.7 million in the three months ended March 31, 2016, increasing income tax expense by $0.8 million for PNM and reducing income tax expense by $0.1 million for the Corporate and Other segment. See Note 8 for a discussion of the impacts on income tax expense resulting from the adoption of Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718).

(14) Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP, as is PNMR Services Company, a wholly-owned subsidiary of PNMR that provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

	Three Months Ended
	March 31,
	2017		2016
	(In thousands)
Services billings:
PNMR to PNM	$	24,402	$	22,734
PNMR to TNMP	8,137		7,048
PNM to TNMP	85		106
TNMP to PNMR	35		10
Interest billings:
PNMR to TNMP	31		50
PNM to PNMR	43		36
Income tax sharing payments:
PNMR to PNM	—		—
PNMR to TNMP	—		—

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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 768,000 residential, commercial, and industrial customers and end-users of electricity in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP.

Strategic Goals

PNMR is focused on achieving three key strategic goals:

• Earning authorized returns on regulated businesses

• Delivering above industry-average earnings and dividend growth

• Maintaining solid investment grade credit ratings

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

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

• Delivering a superior customer experience

• Demonstrating environmental stewardship in their business operations

• Supporting the communities in their service territories

Earning Authorized Returns on Regulated Businesses

PNMR’s success in accomplishing its strategic goals is highly dependent on two key factors: fair and timely regulatory treatment for its utilities and the utilities’ strong operating performance. The Company has multiple strategies to achieve favorable regulatory treatment, all of which have as their foundation a focus on the basics: safety, operational excellence, and customer satisfaction, while engaging stakeholders to build productive relationships. Both PNM and TNMP seek cost recovery for their investments through general rate cases and various rate riders.

Fair and timely rate treatment from regulators is crucial to PNM and TNMP in earning their allowed returns and critical for PNMR to achieve its strategic goals. PNMR believes that earning allowed returns would be viewed positively by credit rating agencies and would further improve the Company’s ratings, which could lower costs to utility customers. Also, earning allowed returns should result in increased earnings for PNMR, which would lead to increased growth in EPS.

Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 12.

State Regulation

New Mexico Rate Cases – On September 28, 2016, the NMPRC issued an order that authorizes PNM to implement an increase in base non-fuel rates of $61.2 million for New Mexico retail customers, effective for bills sent after September 30, 2016. This order was on PNM’s application for a general increase in retail electric rates (the “NM 2015 Rate Case”) filed in August 2015. PNM’s application requested an increase in base non-fuel revenues of $121.5 million based on a future test year (“FTY”) beginning October 1, 2015. The primary drivers of the revenue deficiency were infrastructure investments and declines in forecasted

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energy sales due to successful energy efficiency programs and other economic factors. PNM also proposed changes to rate design to provide fairer pricing across rate classes and better align cost recovery with cost causation.

Following public hearings, the Hearing Examiner in the case issued a recommended decision (“RD”) in August 2016 proposing an increase in non-fuel revenues of $41.3 million. The NMPRC’s September 26, 2016 order approved many aspects of the RD, including the determination that PNM was imprudent in purchasing the 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 the BDT equipment on SJGS Units 1 and 4. However, the order also made certain significant modifications to the RD. Major components of the difference between the increase in non-fuel revenues approved in the order and PNM’s request, include:

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

• Inclusion of the January 2016 purchase of the assets underlying three leases of capacity, totaling 64.1 MW, of PVNGS Unit 2 (Note 6) 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 6)

• Disallowance of recovery of the costs associated with converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS (Note 12), but allows recovery of avoided operating and maintenance expenses of $0.3 million annually related to BDT; PNM’s share of the costs of installing the BDT equipment was $52.3 million, $40.0 million of which PNM requested be included in rate base in the NM 2015 Rate Case

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

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

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

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

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

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

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

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

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

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

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

• The final rate design

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

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NEE subsequently filed a motion for a partial stay of the order at the NM Supreme Court. This motion was denied. The NM Supreme Court stated that the court’s intent was to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits. Otherwise, the court has taken no action with respect to the appeals. On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule is anticipated to be completed by June 28, 2017. Although appeals of regulatory actions of the NMPRC have a priority at the NM Supreme Court under New Mexico law, there is no required time frame for the court to act on the appeals.

PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicates it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the issues, those issues would be remanded back to the NMPRC for further action. PNM estimates that it will take a minimum of 15 months, from the date PNM filed its appeal, for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order will remain in effect. Accordingly, at September 30, 2016, PNM recorded a pre-tax regulatory disallowance of $11.3 million, representing 15 months of capital cost recovery on its investments that the order disallowed, as well as amounts recorded as regulatory assets and deferred charges that the order disallowed and which PNM did not challenge in its appeal. Additional losses will be recorded if the currently estimated 15 month 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 prudently incurred and that PNM is entitled to full recovery of those investments through the ratemaking process. PNM believes it is reasonably possible that its appeals will be successful, but cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record additional pre-tax losses related to any unsuccessful issues. The March 31, 2017 book values of PNM’s investments that the order disallowed, after considering the loss recorded in 2016, were $76.9 million for the 64.1 MW of purchased capacity in PVNGS Unit 2, $39.9 million for the PVNGS Unit 2 disallowed capital improvements, and $50.0 million for the BDT equipment.

PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, if the Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $154.9 million at March 31, 2017 (which amount includes $76.9 million that is the subject of PNM’s appeal discussed above) after considering the loss recorded in 2016. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and prepaid pension asset in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have financial impact to PNM.

PNM is unable to predict the outcome of this matter.

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

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

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

• ROE of 10.125%

• Drivers of revenue deficiency

◦ Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (see below and Note 12)

◦ Infrastructure investments, including environmental upgrades at Four Corners

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

◦ Updates in the FERC/retail jurisdictional allocations

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

◦ Increased customer and demand charges

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

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The NMPRC scheduled a public hearing to begin on June 5, 2017, ordered that a settlement conference should be held, and that any resulting stipulation should be filed by March 27, 2017. Settlement discussions have been held, but no agreements were reached by March 27, 2017. PNM and several intervenors filed an unopposed motion with the NMPRC to extend by one month the procedural schedule, including the date for filing a stipulation. On April 12, 2017, the NMPRC issued an order modifying the procedural schedule to allow for additional settlement discussion. Under the revised schedule, any settlement stipulation was to be filed by April 27, 2017 and the public hearing would begin on July 10, 2017. The parties to the case have engaged in negotiations for a possible settlement. PNM and representatives of several intervenors have reached an agreement on the parameters for a settlement in this proceeding. On April 27, 2017, PNM and several intervenors filed a motion with the NMPRC to extend the deadline for filing a stipulation to May 5, 2017. The extension would provide additional time for the parties to reach a final agreement and obtain any necessary approvals of their respective governing boards or management. The motion is subject to approval by the Hearing Examiner. Upon filing, a settlement would require the approval of the NMPRC in order to take effect. PNM cannot predict the outcome of this matter.

Advanced Metering –In September 2011, TNMP began its deployment of advanced meters for homes and businesses across its Texas service area. TNMP completed its mass deployment in 2016 and has installed more than 242,000 advanced meters. As part of the State of Texas’ long-term initiative to create an advanced electric grid, installation of advanced meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. In addition, TNMP recently completed installation of a new outage management system that will leverage capabilities of the advanced metering infrastructure to enhance TNMP’s responsiveness to outages.

On February 26, 2016, PNM filed an application with the NMPRC requesting approval of a project to replace its existing customer metering equipment with Advanced Metering Infrastructure (“AMI”). The application also asks the NMPRC to authorize the recovery, in future ratemaking proceedings, of the cost of the project, up to $87.2 million, as well as to approve the recovery of the remaining undepreciated investment in existing metering equipment estimated to be approximately $33 million and the costs of customer education and severance for any affected employees. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. Hearings on the AMI application concluded in March 2017. PNM is considering requesting a three-month suspension of the AMI filing in order to consider rate design opportunities, update the cost/benefit analysis, and consider if there is interest among the parties to settle the case.  PNM cannot predict the outcome of this matter.

PVNGS Unit 3 –Currently, PNM’s 134 MW interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates. The power generated from that interest is sold into the wholesale market and any earnings or losses are realized by shareholders. As part of compliance with the requirements for BART at SJGS discussed below, the NMPRC approved including PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018. PVNGS Unit 3 is included as a jurisdictional resource in PNM’s NM 2016 Rate Case.

Rate Riders and Interim Rate Relief –The PUCT has approved mechanisms that allow TNMP to recover capital invested in transmission and distribution projects without having to file a general rate case. This permits more timely recovery of investments. The PUCT has also approved riders that allow TNMP to recover amounts related to AMS, energy efficiency, third-party transmission costs, and the CTC. The NMPRC has approved rate riders for renewable energy and energy efficiency that allow for more timely recovery of investments and improve PNM’s ability to earn its authorized return.

TNMP General Rate Case – TNMP’s last general rate case was filed in 2010 with new rates becoming effective on February 1, 2011. In connection with TNMP’s deployment of its AMS, TNMP has committed to file a general rate case no later than September 1, 2018. TNMP currently anticipates filing its general rate case in May 2018 using a 2017 calendar year test period.  New rates are expected to be effective during January 2019. 

FERC Regulation

Rates PNM charges for transmission customers and wholesale generation services customers are subject to traditional rate regulation by FERC. For a number of years, PNM allocated a portion of its generation assets to serve FERC wholesale generation services customers.  Recently, the low natural gas price environment has resulted in market prices for power to be substantially lower than what PNM is able to offer wholesale generation customers under the cost of service model that FERC requires PNM to use.  As a result of this change in market conditions, PNM has not been earning an adequate return on the assets required to serve wholesale generation contracts. Consequently, PNM has decided to stop pursuing wholesale generation contracts. Currently, PNM has no full-requirements wholesale generation customers.

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

On October 29, 2015, PNM and NEC entered into, and filed with FERC, a settlement agreement, which FERC approved in January 2016. Under the agreement, PNM served all of NEC’s load through December 31, 2015 at rates that are substantially consistent with those provided under the PSA. In 2016, PNM served all of NEC’s load at reduced demand and energy rates from those under the PSA. The PSA terminated on December 31, 2016. In 2017, PNM is serving 10 MW of NEC’s load under a short-term coordination tariff at a rate lower than provided under the PSA, but higher than prices available under short-term market rates at the time of the settlement. For the three months ended March 31, 2017 and 2016, amounts billed to NEC were $1.1 million and $5.4 million. Although the settlement agreement will negatively impact results of operations in 2017, PNM expects to be able to mitigate these impacts through market sales of power that would have been sold to NEC, reductions in fuel and transmission expenses, and other measures. PNM’s NM 2016 Rate Case discussed above proposes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve NEC.

Delivering Above Industry-Average Earnings and Dividend Growth

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

PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. PNMR expects to provide above industry-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target. The Board will continue to evaluate the dividend on an annual basis, considering sustainability and growth, capital planning, and industry standards. The Board approved the following increases in the indicated annual common stock dividend:

Approval Date	Percent Increase
February 2012	16%
February 2013	14%
December 2013	12%
December 2014	8%
December 2015	10%
December 2016	10%

Maintaining Solid Investment Grade Credit Ratings

The Company is committed to maintaining solid investment grade credit ratings in order to reduce the cost of debt financing and to help ensure access to credit markets, when required. See the subheading Liquidity included in the full discussion of Liquidity and Capital Resources below for the specific credit ratings for PNMR, PNM, and TNMP. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade with a stable outlook.

Business Focus

PNMR strives to create enduring value for customers, communities, and shareholders. PNMR’s strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power. PNMR works closely with customers, stakeholders, legislators, and regulators to ensure that resource plans and infrastructure investments benefit from robust public dialogue and balance the diverse needs of our communities. Equally important is the focus of PNMR’s utilities on customer satisfaction and community engagement.

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Reliable and Affordable Power

PNMR and its utilities are aware of the important roles they play in enhancing economic vitality in their service territories. Management believes that maintaining strong and modern electric infrastructure is critical to ensuring reliability and supporting economic growth. When contemplating expanding or relocating their operations, businesses consider energy affordability and reliability to be important factors. PNM and TNMP strive to balance service affordability with infrastructure investment to maintain a high level of electric reliability and to deliver a superior customer experience. Investing in PNM’s and TNMP’s infrastructure is critical to ensuring reliability and meeting future energy needs. Both utilities have long-established records of providing customers with reliable electric service.

Utility Plant Investments

During the 2014 to 2016 period, PNM and TNMP together invested $1,541.4 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. PNM completed the 40 MW natural gas-fired La Luz peaking generating station located near Belen, New Mexico in December 2015. PNM also completed installation of SNCR and BDT equipment on SJGS Units 1 and 4 in early 2016 and the addition of 40 MW of PNM-owned solar PV facilities in 2015. In addition, on January 15, 2016, PNM completed the $163.3 million acquisition of 64.1 MW of capacity in PVNGS Unit 2 that had previously been leased to PNM.

Integrated Resource Plan

NMPRC rules require that investor-owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated energy demand with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities.

PNM has begun its process for the 2017 IRP that PNM intends to file by July 3, 2017. In the NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 11, PNM is required to make a filing in 2018 to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after June 30, 2022. To facilitate the 2018 filing, PNM is developing two resource portfolios in the 2017 IRP, one with SJGS continuing beyond mid-2022 and one where it is shut down. On March 17, 2017, PNM announced that preliminary results of its analysis indicate that retirement of SJGS in 2022 could be cost-effective for customers.

On April 20, 2017, PNM released a draft of the 2017 IRP. Key findings in that draft 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 built from Eastern New Mexico to PNM’s service territory

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

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

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

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

• PNM should pursue securitization legislation to provide additional customer cost savings and provide funds for replacement resources

The draft of the 2017 IRP sets forth the results of the IRP process to date. Additional input through a continuing public advisory process could lead to further analysis of the resource mix, which could result in revisions from the draft plan. PNM must

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file the final IRP by July 3, 2017. PNM cannot predict the ultimate outcome of the 2017 IRP process or whether the NMPRC will approve subsequent filings that would encompass actions to implement the conclusions of the 2017 IRP.

Environmentally Responsible Power

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

• Developing strategies to meet regional haze rules at the coal-fired SJGS as cost-effectively as possible while providing broad environmental benefits that also demonstrate progress in addressing new federal regulations for CO₂ emissions from existing power plants

• Preparing to meet New Mexico’s increasing renewable energy requirements as cost-effectively as possible

• Increasing energy efficiency participation

SJGS

Regional Haze Rule Compliance Plan – On December 16, 2015, PNM received NMPRC approval for the plan to comply with the EPA regional haze rule at SJGS that minimizes the cost impact to customers while still achieving broad environmental benefits. Under the approved plan, the installation of SNCRs on SJGS Units 1 and 4 was completed in early 2016 and Units 2 and 3 will be retired by the end of 2017. The plan provides for similar visibility improvements, but at a lower cost to PNM customers than a previous EPA ruling that would have required the installation of more expensive SCRs on all four units at SJGS. The plan has the added advantage of reducing other emissions in addition to NOx, including SO₂, particulate matter, CO₂, and mercury, as well as reducing water usage. Additional information is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 11.

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

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

• Is granted a CCN to acquire an additional 132 MW in SJGS Unit 4, with an initial book value of zero, plus SNCR costs and whatever portion of BDT costs the NMPRC determines to be reasonable and prudent to be allowed for recovery in rates (see New Mexico Rate Cases above and Note 12)

• Is granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017 (currently estimated to be approximately $156 million)

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

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

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

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

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

At December 31, 2015, PNM recorded pre-tax losses aggregating $165.7 million to reflect the write-off of the 50% of the estimated December 31, 2017 net book value of SJGS Units 2 and 3 that will not be recovered, the other unrecoverable costs, and the increase in the estimated liability recorded for coal mine reclamation resulting from the new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”). In 2016, PNM recorded additional pre-tax losses of $3.7 million resulting from revised estimates of these items. Additional information about the CSA is discussed below and in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 11.

On January 14, 2016, NEE filed a Notice of Appeal with the NM Supreme Court of the NMPRC’s December 16, 2015 order. The NM Supreme Court has taken no action on the appeal and there is no required time frame for the court to act on the appeals. On March 31, 2016, NEE filed a complaint against PNM with the NMPRC regarding the financing provided by NM Capital to facilitate the sale of SJCC. The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability

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to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. The NMPRC has taken no action on this matter.

SJGS Ownership Restructuring –In connection with the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants expressed a desire to exit their ownership in the plant. As a result, the SJGS participants negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items.

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

• Capacity acquisition – On December 31, 2017, PNM will acquire 132 MW of the exiting owners’ capacity in SJGS Unit 4 and PNMR Development agreed to acquire 65 MW of such capacity. It is currently anticipated that PNMR Development will transfer the rights and obligations related to the 65 MW to PNM prior to December 31, 2017 in order to facilitate dispatch of power from that capacity. As ordered by the NMPRC, PNM would treat the 65 MW as merchant utility plant that would be excluded from retail rates.

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

• Coal supply – The RA became effective contemporaneously with the effectiveness of the new CSA for SJGS. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which occurred on January 31, 2016. In support of the closing of the mine purchase and to facilitate PNM customer savings, NM Capital, a wholly owned subsidiary of PNMR, provided funding of $125.0 million to Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price. NM Capital was able to provide the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement with a commercial bank. PNMR guarantees NM Capital’s obligations to the bank. The Westmoreland Loan has a maturity date of February 1, 2021 and initially bears interest at a rate of 7.25% plus LIBOR and escalates over time. Such rate is 9.25% plus LIBOR for the period from February 1, 2017 through January 31, 2018. WSJ must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. The Westmoreland Loan has been structured to encourage prepayments and early retirement of the debt. As of April 24, 2017, the balance of the Westmoreland Loan was $85.4 million. The next principal payment of $9.6 million plus interest of $2.2 million is due on May 2, 2017. As of April 24, 2017, $11.8 million was held in a SJCC restricted bank account that is to be used solely to service the Westmoreland Loan.

• Coal mine reclamation – Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation costs associated with the supply of coal from the San Juan mine. In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds, which currently aggregate $118.7 million, with the NMMMD. PNMR has arrangements under which a bank has issued $30.3 million in letters of credit to facilitate posting of the required reclamation bonds. See Note 11.

Other SJGS Environmental Matters –In addition to the regional haze rule, SJGS is required to comply with other rules currently being developed or implemented that affect coal-fired generating units, including rules regarding GHG under Section 111(d) of the CAA. Implementation of the Clean Power Plan, which was published by EPA in October 2015, is currently stayed by order of the US Supreme Court pending further proceedings before the DC Circuit. Oral argument was heard by the DC Circuit in September 2016, but the court has taken no action. On March 28, 2017, President Trump issued an Executive Order on Energy Independence.  The order sets out two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is affordable, reliable, safe, secure, and clean.  The order rescinds various actions undertaken by the previous administration and directs the EPA Administrator to review and if appropriate suspend, revise, or rescind the Clean Power Plan, as well as other environmental regulations. PNM estimates that implementation of the BART plan at SJGS, which is discussed above, should provide a significant step for New Mexico to meet its ultimate compliance with Section 111(d). PNM is unable to predict the impact of this rule on its fossil-fueled generation.

Because of environmental upgrades completed in 2009, SJGS is well positioned to outperform the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. The major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO₂, particulate matter, and mercury. Since 2006, SJGS has reduced NOx emissions by 46%, SO₂ by 78%, particulate matter by 75%, and mercury by 98%.

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Water Conservation and Solid Waste Reduction

PNM continues its efforts to reduce the amount of fresh water used to make electricity (about 20% more efficient than in 2007). Continued growth in PNM’s fleet of solar, wind, and geothermal energy sources, energy efficiency programs, and innovative uses of gray water and air-cooling technology have contributed to this reduction. Water usage will continue to decline as PNM substitutes less fresh-water-intensive generation resources to replace SJGS Units 2 and 3 starting in 2018, when water consumption at that plant will be reduced by around 50%. Focusing on responsible stewardship of New Mexico’s scarce water resources improves PNM’s water-resilience in the face of persistent drought and ever-increasing demands for water to spur the growth of New Mexico’s economy. In addition to the above areas of focus, the Company is working to reduce the amount of solid waste going to landfills through increased recycling and reduction of waste. In 2016, 19 of the Company’s 23 facilities met the waste diversion goal of a 60% diversion rate, while recycling at least the same number of waste streams as 2015. The Company expects to continue to do well in this area in the future.

Renewable Energy

PNM’s renewable procurement strategy includes utility-owned solar capacity, as well as wind and geothermal energy purchased under PPAs. As of December 31, 2016, PNM had 107 MW of utility-owned solar capacity, including 40 MW completed in 2015. The NM 2015 Rate Case discussed above includes recovery of the costs associated with the 40 MW solar facilities. As discussed in Note 12, PNMR Development will construct and own 30 MW of new solar capacity that PNM will use to supply power to a new data center being constructed by Facebook Inc. in PNM’s service territory. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 66.8 MW at March 31, 2017. PNM also owns the 500 KW PNM Prosperity Energy Storage Project, which uses advanced batteries to store solar power and dispatch the energy either during high-use periods or when solar production is limited. The project was one of the first combinations of battery storage and PV energy in the nation and involved extensive research and development of advanced grid concepts. The facility also was the nation’s first solar storage facility fully integrated into a utility’s power grid. Since 2003, PNM has purchased the output from a 204 MW wind facility and began purchasing the output of another existing 102 MW wind energy center on January 1, 2015. PNM has a 20-year agreement to purchase energy from a geothermal facility built near Lordsburg, New Mexico. The facility began providing power to PNM in January 2014. The current capacity of the geothermal facility is 4 MW. PNM also purchases RECs as necessary to meet the RPS.

The majority of these renewable resources are key means for PNM to meet the RPS and related regulations that require PNM to achieve prescribed levels of energy sales from renewable sources, if that can be accomplished without exceeding the RCT limit set by the NMPRC. PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM’s 2017 renewable energy procurement plan meets RPS and diversity requirements for 2017 and 2018 using existing resources and does not propose any significant new procurements. PNM projects that its plan will slightly exceed the RCT in 2017, but will be within the RCT in 2018. The NMPRC approved the plan on November 23, 2016. The NMPRC found that a variance regarding the RCT is not required. PNM will continue to procure renewable resources while balancing the impact to customers’ bills in order to meet New Mexico’s escalating RPS requirements.

Energy Efficiency

Energy efficiency also plays a significant role in helping to keep customers’ electricity costs low while meeting their energy needs. PNM’s and TNMP’s energy efficiency and load management portfolios continue to achieve robust results. In 2016, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 74 GWh. This is equivalent to the annual consumption of approximately 11,000 homes in PNM’s service territory. PNM’s load management and annual energy efficiency programs also help lower peak demand requirements. TNMP’s energy efficiency programs in 2016 resulted in energy savings totaling an estimated 22 GWh. This is equivalent to the annual consumption of approximately 2,250 homes in TNMP’s service territory. In April 2016 and again in April 2017, TNMP was recognized by Energy Star for TNMP’s successful energy efficiency efforts. TNMP received the “Partner of the Year Energy Efficiency Delivery Award” for its High-Performance Homes Program.

Customer, Stakeholder, and Community Engagement

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

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its customers, identifying and establishing valued services and programs, and proactively communicating and engaging with customers at regional and community levels. PNM’s focus on the customer experience has resulted in increasing scores in the JD Power Electric Utility Residential Customer Satisfaction Study.

The Company has leveraged a number of communications channels and strategic content to better serve and engage its many stakeholders. PNM’s website, www.pnm.com, provides the details of major regulatory filings, including general rate requests, as well as the background on PNM’s efforts to maintain reliability, keep prices affordable, and protect the environment. The website is designed to be a resource for the facts about PNM’s operations and community support efforts, including plans for building a sustainable energy future for New Mexico. In September 2016, PNMR launched 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 sustainability information related to the operations of PNM and TNMP. The information is presented under four main headings: Environment, Social, Economic, and Governance.

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

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

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

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

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

Economic Factors

PNM –In the three months ended March 31, 2017, PNM experienced a decrease in weather normalized retail load of 0.8% compared to 2016, primarily due to decreased commercial and industrial sales consistent with recent flattening in Albuquerque’s employment growth.  The sales decreases reflect a continued sluggish economy in New Mexico. However, some of the previously announced successful economic development efforts, such as the selection of a site in New Mexico for a data center by Facebook Inc. within PNM’s service territory, appear to have started their hiring process. There also have been some expansions of existing businesses, particularly in healthcare, education, and professional services. The economy in New Mexico continues to have mixed indicators and experience softness that is driven primarily by low oil and natural gas prices. Although PNM does not serve the regions of the state that produce oil and gas, it is anticipated that the impacts of layoffs and the decrease in state royalty revenues will further soften the economies in PNM’s service territory, particularly in the Albuquerque metropolitan area and Santa Fe, as the state deals with budget shortfalls.

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

TNMP –In the three months ended March 31, 2017, TNMP experienced an increase in volumetric weather normalized retail load of 5.4% compared to 2016. Most of TNMP’s industrial and larger commercial customers are billed based on their peak demand. The Texas economy continues to grow, primarily due to its diverse base, which helps compensate for the weakness in the energy sector. The relocation of some national and global corporate headquarters to the Dallas-Fort Worth area has led to growth in commercial customers and also contributes to growth in residential and small business customers. TNMP continues to add new transmission customers in its West Texas service territory where oil and gas production continues to grow.

Results of Operations

Net earnings attributable to PNMR were $22.9 million, or $0.29 per diluted share in the three months ended March 31, 2017 compared to $10.5 million, or $0.13 per diluted share, in 2016. Among other things, earnings in the three months ended March 31, 2017 benefited from additional revenues due to the rate increase approved in the NM 2015 Rate Case at PNM, rate increases and increased load at TNMP, lower plant maintenance costs at PNM, and excess tax benefits related to stock compensation recognized under a new accounting standard (Note 8). These increases were offset by milder weather at PNM and TNMP, lower revenue from NEC, and increased depreciation and property taxes due to increased plant in service. Additional information on factors impacting results of operation for each segment is discussed under Results of Operations below.

Liquidity and Capital Resources

PNMR and PNM have revolving credit facilities that expire in October 2021. The PNMR and PNM facilities have capacities of $300.0 million and $400.0 million through October 2020 and $290.0 million and $360.0 million from November 2020 through October 2021. Both facilities provide for short-term borrowings and letters of credit. In addition, PNM has a $50.0 million revolving credit facility, which expires in January 2018, with banks having a significant presence in New Mexico and TNMP has a $75.0 million revolving credit facility, which expires in September 2018. Total availability for PNMR on a consolidated basis was $605.3 million at April 24, 2017. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. PNMR also has intercompany loan agreements with each of its subsidiaries.

PNMR projects that its consolidated capital requirements, consisting of construction expenditures and dividends, will total $2,472.6 million for 2017-2021, including amounts expended through March 31, 2017. The construction expenditures include estimated amounts for environmental upgrades at Four Corners, the 30 MW of new solar capacity to supply power to a new data center being constructed by Facebook Inc. (Note 12), and a 40 MW gas-fired peaking generating facility to be completed in 2020. PNMR also has consolidated maturities, mandatory remarketings, and other repayments of short-term and long-term debt aggregating $515.5 million in the period from April 1, 2017 through March 31, 2018 and $556.8 million in the remainder of 2018. Furthermore the $50.0 million PNM New Mexico Credit Facility expires in January 2018 and the $75.0 million TNMP Revolving Credit Facility expires in September 2018. In addition to internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing in the form of debt refinancing, new debt issuances, and/or new equity in order to fund its capital requirements during the 2017-2021 period. The Company currently believes that its internal cash generation, existing credit arrangements, and access to public and private capital markets will provide sufficient resources to meet the Company’s capital requirements.

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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.

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

	Three Months Ended March 31,
	2017		2016		Change
	(In millions, except per share amounts)
Net earnings attributable to PNMR	$	22.9	$	10.5	$	12.4
Average diluted common and common equivalent shares	80.1		80.2		(0.1		)
Net earnings attributable to PNMR per diluted share	$	0.29	$	0.13	$	0.16

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

	Three Months Ended
	March 31, 2017
	(In millions)
PNM	$	12.4
TNMP	0.1
Corporate and Other	(0.2		)
Net change	$	12.4

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 3 for more information on PNMR’s operating segments.

PNM

PNM’s utility margin is defined as electric operating revenues less cost of energy, which consists primarily of fuel and purchase power costs. PNM believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since substantially all fuel and purchase power costs are offset in revenues, as those costs are passed through to customers under PNM’s FPPAC.

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The following table summarizes the operating results for PNM:

	Three Months Ended March 31,
	2017			2016			Change
	(In millions)
Electric operating revenues	$	251.6		$	235.6		$	16.0
Cost of energy	81.3			72.4			8.9
Utility margin	170.2			163.2			7.0
Operating expenses	95.9			108.0			(12.1		)
Depreciation and amortization	36.0			31.9			4.1
Operating income	38.3			23.3			15.0
Other income (deductions)	10.5			9.5			1.0
Interest charges	(21.0		)	(21.6		)	0.6
Segment earnings before income taxes	27.8			11.2			16.6
Income (taxes)	(7.7		)	(3.6		)	(4.1		)
Valencia non-controlling interest	(3.5		)	(3.3		)	(0.2		)
Preferred stock dividend requirements	(0.1		)	(0.1		)	—
Segment earnings	$	16.5		$	4.1		$	12.4

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
	2017	2016	Change
	(Gigawatt hours, except customers)
Residential	749.5	772.8	(3.0	)%
Commercial	826.6	864.0	(4.3	)
Industrial	207.9	218.5	(4.9	)
Public authority	53.3	51.2	4.1
Economy energy service (1)	186.8	208.9	(10.6	)
Firm-requirements wholesale	21.6	119.1	(81.9	)
Other sales for resale (2)	1,085.4	655.4	65.6
	3,131.1	2,889.9	8.3	%
Average retail customers (thousands)	520.9	517.4	0.7	%

⁽¹⁾ PNM purchases energy for a major customer on the customer’s behalf and delivers the energy to the customer’s location through PNM’s transmission system. PNM charges the customer for the cost of the energy as a direct pass through to the customer with only a minor impact in utility margin resulting from providing ancillary services.

⁽²⁾ Increase in 2017 includes the hazard sharing agreement with Tri-State (Note 12). Increase is also due to more power available for off-system sales, primarily related to SJGS and Four Corners. Substantially all of the margin from off-system sales is returned to customers through the FPPAC.

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Operating Results – Three months ended March 31, 2017 compared to 2016

The following table summarizes the significant changes to utility margin:

		Three Months Ended March 31, 2017
		Change
Utility margin:		(In millions)
	Customer usage/load –PNM’s weather normalized retail KWh sales decreased 0.8%; decreased commercial and industrial sales were partially offset by increases in residential sales	$	(0.6	)
	Rate relief – Additional revenue due to rate increase approved by the NMPRC on September 28, 2016 and certain fuel costs being passed through the FPPAC	13.4
	Weather – Milder weather; heating degree days were lower by 12.3% in 2017	(2.9		)
	Leap Year – Decrease in revenue due to additional day in 2016	(1.6		)
	Transmission –Higher revenues under formula transmission rates and addition of a new customer	1.9
	Wholesale contracts –Primarily due to NEC (Note 12)	(2.8		)
	Unregulated margin –Higher hedged prices for PVNGS Unit 3 sales	1.0
	Rate riders –Includes renewable energy and energy efficiency riders, which are partially offset in operating expenses, depreciation and amortization, and interest charges	(1.1		)
	Net unrealized economic hedges –Primarily related to hedges of PVNGS Unit 3 power sales	(0.1		)
	Other	(0.2		)
	Net Change	$	7.0

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

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		Three Months Ended March 31, 2017
		Change
Operating expenses:		(In millions)
	Lower plant maintenance costs	$	(7.9	)
	2016 regulatory disallowance due to change in estimated write-offs associated with the SJGS BART determination and ownership restructuring (Note 11)	(0.8		)
	Lower property and casualty expense due to lower claims experience	(0.4		)
	Lower employee related expenses and outside consulting costs	(2.1		)
	Higher capitalized administrative and general expenses due to higher construction spending in 2017	(0.4		)
	Costs associated with new software implementation	0.9
	Lower rent expense associated with PVNGS leases (Note 6)	(0.9		)
	Other	(0.5		)
	Net Change	$	(12.1	)

		Three Months Ended March 31, 2017
		Change
Depreciation and amortization:		(In millions)
	Higher depreciation rates approved by the NMPRC as part of PNM’s 2015 NM Rate Case	$	1.5
	Increased utility plant in service	2.6
	Net Change	$	4.1

Other income (deductions):
	Greater gains on available-for-sale securities in the NDT and coal mine reclamation trusts	$	0.4
	Higher interest income and lower trust expenses related to available-for-sale securities in the NDT and coal mine reclamation trusts	0.3
	Interest income from third party transmission service provider due to FERC ruling	1.0
	Higher equity AFUDC	0.4
	Lower income from refined coal (a third-party pre-treatment process); income is now passed through to customers as ordered in PNM’s NM 2015 Rate Case	(1.2		)
	Other	0.1
	Net Change	$	1.0

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Interest charges:
	Lower interest on $146.0 million of PCRBs refinanced in September 2016	$	0.8
	Other	(0.2		)
	Net Change	$	0.6

Income taxes:
	Increase due to higher segment earnings before income taxes	$	(6.4	)
	Impacts of phased-in reduction in New Mexico corporate income tax rates	0.8
	Decrease due to excess tax benefits related to stock compensation awards (Note 13)	1.3
	Other	0.2
	Net Change	$	(4.1	)

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TNMP

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

The following table summarizes the operating results for TNMP:

	Three Months Ended March 31,
	2017			2016			Change
	(In millions)
Electric operating revenues	$	78.6		$	75.4		$	3.2
Cost of energy	21.5			19.9			1.6
Utility margin	57.1			55.4			1.7
Operating expenses	23.8			22.4			1.4
Depreciation and amortization	15.4			14.5			0.9
Operating income	18.0			18.6			(0.6		)
Other income (deductions)	0.7			0.6			0.1
Interest charges	(7.4		)	(7.4		)	—
Segment earnings before income taxes	11.3			11.8			(0.5		)
Income (taxes)	(3.7		)	(4.3		)	0.6
Segment earnings	$	7.6		$	7.5		$	0.1

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
	2017	2016	Change
Volumetric load (1) (GWh)
Residential	577.0	578.7	(0.3	)%
Commercial and other	9.2	11.2	(17.9	)
Total volumetric load (1)	586.2	589.9	(0.6	)%
Demand-based load (2) (MW)	3,871.7	3,659.5	5.8	%
Average retail consumers (thousands)(3)	246.8	243.9	1.2	%

⁽¹⁾ Volumetric load customers are billed on KWh usage

⁽²⁾ Demand-based load is billed on monthly KW peak. 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 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, 2017 compared to 2016

The following table summarizes the significant changes to utility margin:

		Three Months Ended March 31, 2017
		Change
Utility margin:		(In millions)
	Rate relief –Transmission cost of service rate increases in March 2016, September 2016, and March 2017	$	1.3
	Customer usage/load –5.4% increase in weather normalized retail KWh sales, primarily related to the residential class; higher demand-based revenues for large commercial and industrial retail customers; and increased wholesale transmission load; the average number of retail customers increased 1.2%	1.9
	Rate riders – Impacts of rate riders, including the AMS surcharge, CTC surcharge, energy efficiency rider, and transmission cost recovery factor, which are partially offset in operating expenses, depreciation and amortization, and interest charges	(0.9		)
	Weather – Milder weather in 2017; heating degree days were 25.5% lower in 2017	(0.8		)
	Other	0.2
	Net Change	$	1.7

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

		Three Months Ended March 31, 2017
		Change
Operating expenses:		(In millions)
	Higher employee related expenses	$	0.6
	Lower rate rider related costs, which are offset in utility margin	(0.5		)
	Increased property taxes due to increases in utility plant in service and higher assessed values	0.2
	Higher property and casualty expense due to increased claims	0.3
	Costs associated with new software implementation	0.4
	Other	0.4
	Net Change	$	1.4

Depreciation and amortization:
	Increase primarily due to increases in utility plant in service	$	0.9

Other income (deductions):
	Increased equity AFUDC	$	0.2
	Other	(0.1		)
	Net Change	$	0.1

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		Three Months Ended March 31, 2017
		Change
Interest charges:		(In millions)
	Increase due to the issuance of $60.0 million of long-term debt on February 10, 2016	$	0.2
	Other	(0.2		)
	Net Change	$	—

Income taxes:
	Decrease due to lower segment earnings before income taxes	$	0.2
	Decrease due to excess tax benefits related to stock compensation awards (Note 13)	0.5
	Other	(0.1		)
	Net Change	$	0.6

Corporate and Other

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

	Three Months Ended March 31,
	2017			2016			Change
	(In millions)
Total revenues	$	—		$	—		$	—
Cost of energy	—			—			—
Utility margin	—			—			—
Operating expenses	(4.7		)	(3.1		)	(1.6		)
Depreciation and amortization	5.0			3.5			1.5
Operating income (loss)	(0.3		)	(0.3		)	—
Other income (deductions)	1.7			1.0			0.7
Interest charges	(3.3		)	(2.5		)	(0.8		)
Segment earnings (loss) before income taxes	(1.9		)	(1.8		)	(0.1		)
Income (taxes) benefit	0.6			0.8			(0.2		)
Segment earnings (loss)	$	(1.3	)	$	(1.1	)	$	(0.2	)

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

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Operating Results – Three months ended March 31, 2017 compared to 2016

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

		Three Months Ended March 31, 2017
		Change
Other income (deductions):		(In millions)
	2016 costs paid by PNMR Development related to obligations under the SJGS restructuring agreement	$	0.6
	Other	0.1
	Net Change	$	0.7

Interest charges:
	Issuance of the $100.0 million 2016 Two-Year Term Loan in December 2016	$	(0.4	)
	Issuance of the $100.0 million 2016 One-Year Term Loan in December 2016	(0.4		)
	Higher short term borrowings	(0.2		)
	Repayment of the $150.0 million PNMR Term Loan Agreement	0.5
	Other	(0.3		)
	Net Change	$	(0.8	)

Income taxes:
	Impacts of phased-in reduction in New Mexico corporate income tax rates	$	(0.2	)

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR’s cash flows for the three months ended March 31, 2017 compared to March 31, 2016 are summarized as follows:

	Three Months Ended March 31,
	2017			2016			Change
	(In millions)
Net cash flows from:
Operating activities	$	131.6		$	90.6		$	41.0
Investing activities	(106.6		)	(393.5		)	286.9
Financing activities	(27.2		)	260.7			(287.9		)
Net change in cash and cash equivalents	$	(2.2	)	$	(42.2	)	$	40.0

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 also impact operating cash flows.    

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Cash Flows from Investing Activities

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

	Three Months Ended March 31,
	2017			2016			Change
Cash (Outflows) for Utility Plant Additions	(In millions)
PNM:
Generation	$	(16.4	)	$	(45.7	)	$	29.3
Transmission and distribution	(34.3		)	(22.0		)	(12.3		)
Purchase of previously leased capacity in PVNGS Unit 2	—			(163.3		)	163.3
Four Corners SCRs	(8.2		)	—			(8.2		)
Nuclear fuel	(6.9		)	(7.7		)	0.8
	(65.8		)	(238.7		)	172.9
TNMP:
Transmission	(22.5		)	(18.7		)	(3.8		)
Distribution	(12.8		)	(12.2		)	(0.6		)
AMS	(1.0		)	(2.0		)	1.0
	(36.3		)	(32.9		)	(3.4		)
Corporate and Other:
Computer hardware and software	(10.1		)	(7.0		)	(3.1		)
PNMR Development utility plant additions	(2.6		)	(0.2		)	(2.4		)
	(12.7		)	(7.2		)	(5.5		)
	$	(114.8	)	$	(278.8	)	$	164.0
Cash Inflows (Outflows) on the Westmoreland Loan
Loan origination	$	—		$	(122.3	)	$	122.3
Principal payments	9.6			—			9.6
	$	9.6		$	(122.3	)	$	131.9

Cash Flow from Financing Activities

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

• Short-term borrowings increased $16.0 million in 2017 compared to an increase of $107.4 million in 2016, resulting in a net decrease in cash flows from investing activities of $91.4 million

• Long-term borrowings by NM Capital in 2016 of $122.5 million under the BTMU Term Loan Agreement; NM Capital used the proceeds to provide funds for the Westmoreland Loan; NM Capital made principal paymentson the BTMU Term Loan Agreement of $9.4 million in 2017

• TNMP issued $60.0 million of 3.53% first mortgage bonds in 2016 and used the funds to reduce short-term debt and intercompany debt

Financing Activities

See Note 6 of the Notes to Consolidated Financial Statements in the 2016 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

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• Conditions in the financial markets

• Credit ratings

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

As discussed in Note 11, NM Capital, a wholly owned subsidiary of PNMR, entered into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”), among NM Capital, The Bank of Tokyo-Mitsubishi UFJ, Ltd. (“BTMU”), as lender, and BTMU, as Administrative Agent. The BTMU Term Loan Agreement has a maturity date of February 1, 2021 and bears interest at a rate based on LIBOR plus a customary spread, which aggregated 3.79% at March 31, 2017. The principal balance outstanding under the BTMU Term Loan Agreement was $82.8 million at March 31, 2017. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding for the $125.0 million Westmoreland Loan to a ring-fenced, bankruptcy-remote, special-purpose entity, which is a subsidiary of Westmoreland, to finance the purchase price of the stock of SJCC.

On October 21, 2016, PNMR entered into letter of credit arrangements with JPMorgan Chase Bank, N.A. (the “JPM LOC Facility”) under which letters of credit aggregating $30.3 million were issued to facilitate the posting of reclamation bonds, which SJCC is required to post in connection with permits relating to the operation of the San Juan mine (Note 11). On March 9, 2017, PNMR entered into a four-year hedging agreement whereby it effectively established a fixed interest rate of 1.926% plus a customary spread, subject to change if there is a change in PNMR’s credit rating, for $50.0 million of its variable rate short-term debt. The Finance Committee of the Board has authorized management to enter into additional transactions to hedge against exposure to changes in interest rates on its variable rate debt of up to an additional notional amount of $250.0 million.

At March 31, 2017, interest rates on outstanding borrowings were 1.75% for the $150.0 million PNMR 2015 Term Loan Agreement, 1.83% for the $100.0 million PNMR 2016 One-Year Term Loan, 1.93% for the $100.0 million PNMR 2016 Two-Year Term Loan, and 1.59% for the $175.0 million PNM 2016 Term Loan Agreement. PNMR has a hedging agreement whereby it effectively established a fixed interest rate of 1.927%, subject to change if there is a change in PNMR’s credit rating, for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018.

Capital Requirements

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

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

• Expanding the electric transmission and distribution systems

• Purchasing nuclear fuel

Projected capital requirements, including amounts expended through March 31, 2017, are:

	2017		2018-2021		Total
	(In millions)
Construction expenditures	$	524.3	$	1,559.4	$	2,083.7
Dividends on PNMR common stock	77.3		309.0		386.3
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	602.1	$	1,870.5	$	2,472.6

The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above include environmental upgrades of $44.0 million at Four Corners, $47.2 million for 30 MW of new solar capacity to supply power to a new data center being constructed by Facebook Inc. (Note 12), and $43.7 million for a 40 MW gas-fired peaking generating facility to be completed in 2020. Expenditures for environmental upgrades are estimated to be $35.3 million in 2017, including amounts expended through March 31, 2017. See Note 11 and Commitments and Contractual Obligations below. The ability of PNMR to pay dividends on its common stock is dependent upon the

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ability of PNM and TNMP to be able to pay dividends to PNMR. Note 5 of the Notes to Consolidated Financial Statements in the 2016 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, 2017, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements.

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. PNM has $57.0 million of PCRBs that are subject to mandatory tender for remarketing on June 1, 2017, the $175.0 million PNM 2016 Term Loan Agreement matures on November 17, 2017, the $100.0 million PNMR 2016 One-Year Term Loan matures on December 21, 2017, and the $150.0 million PNMR 2015 Term Loan Agreement matures on March 9, 2018. The BTMU Term Loan Agreement requires that NM Capital utilize all amounts, less taxes and fees, it receives under the Westmoreland Loan to repay the BTMU Term Loan Agreement. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $33.5 million on the BTMU Term Loan Agreement in the twelve months ended March 31, 2018. The Company has additional maturities of short-term and long-term debt of $556.8 million in the remainder of 2018. Note 6 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K contains additional information about the maturities of long-term debt. PNMR and PNM anticipate that funds to repay these long-term debt maturities and term loans will come from entering into new arrangements similar to the existing agreements, borrowing under their revolving credit facilities, issuance of new long-term debt, 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 have capacities of $300.0 million and $400.0 million through October 2020 and $290.0 million and $360.0 million from November 2020 through October 2021. The TNMP Revolving Credit Facility, which expires in September 2018, has a financing capacity of $75.0 million. PNM also has the $50.0 million PNM New Mexico Credit Facility, which expires in January 2018. The Company believes the terms and conditions of these facilities are consistent with those of other investment grade revolving credit facilities in the utility industry.  The Company expects that it will be able to extend or replace these credit facilities under similar terms and conditions prior to their expirations.

The revolving credit facilities and the PNM New Mexico Credit Facility provide short-term borrowing capacity. The revolving credit facilities also allow letters of credit to be issued. Letters of credit reduce the available capacity under the facilities. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. The Company’s business is seasonal with more revenues and cash flows from operations being generated in the summer months. In general, the Company relies on the credit facilities to be the initial funding source for construction expenditures. Accordingly, borrowings under the facilities may increase over time. Depending on market and other conditions, the Company will periodically sell long-term debt and use the proceeds to reduce the borrowings under the credit facilities. Borrowings under the PNMR Revolving Credit Facility ranged from $111.8 million to $183.8 million during the three months ended March 31, 2017. Borrowings under the PNM Revolving Credit Facility ranged from $7.8 million to $65.0 million during the three months ended March 31, 2017. Borrowings under the PNM New Mexico Credit Facility ranged from zero to $26.0 million during the three months ended March 31, 2017. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $22.0 million during the three months ended March 31, 2017. At March 31, 2017, the average interest rate was 2.19% for the PNMR Revolving Credit Facility, 2.11% for the PNM Revolving Credit Facility, and 1.94% for the TNMP Revolving Credit Facility. At March 31, 2017, TNMP had $6.3 million in borrowings from PNMR under its intercompany loan agreement.

The Company currently believes that its capital requirements can be met through internal cash generation, existing or new credit arrangements, and access to public and private capital markets. However, the Company anticipates that it will be necessary to obtain additional long-term financing to fund its capital requirements during the 2017-2021 period. This could include new debt issuances and/or new equity. To cover the difference in the amounts and timing of internal cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements. However, if difficult market conditions experienced during the 2008 recession return, the Company may not be able to access the capital markets or renew credit facilities when they expire. Should that occur, the Company would seek to improve cash flows by reducing capital expenditures and exploring other available alternatives. Also, PNM could consider seeking authorization for the issuance of first mortgage bonds to improve access to the capital markets.

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Information concerning the credit ratings for PNMR, PNM, and TNMP was set forth under the heading Liquidity in the MD&A contained in the 2016 Annual Reports on Form 10-K. As of April 24, 2017, ratings on the Company’s securities were as follows:

	PNMR	PNM	TNMP
S&P
Corporate rating	BBB+	BBB+	BBB+
Senior secured debt	*	*	A
Senior unsecured debt	*	BBB+	*
Preferred stock	*	BBB-	*
Moody’s
Issuer rating	Baa3	Baa2	A3
Senior secured debt	*	*	A1
Senior unsecured debt	*	Baa2	*
* Not applicable

Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade. Both S&P and Moody’s have PNMR, PNM, and TNMP on a stable outlook. However, the ultimate outcome from PNM’s NM 2015 Rate Case, including the pending appeal before the NM Supreme Court, and the outcome of PNM’s NM 2016 Rate Case, as discussed in Note 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 securities, that each rating is subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.

A summary of liquidity arrangements as of April 24, 2017 is as follows:

	PNMR Separate		PNM Separate		TNMP Separate		PNMR Consolidated
	(In millions)
Financing capacity:
Revolving credit facility	$	300.0	$	400.0	$	75.0	$	775.0
PNM New Mexico Credit Facility	—		50.0		—		50.0
Total financing capacity	$	300.0	$	450.0	$	75.0	$	825.0
Amounts outstanding as of April 24, 2017:
Revolving credit facility	$	156.1	$	7.8	$	40.0	$	203.9
PNM New Mexico Credit Facility	—		7.0		—		7.0
Letters of credit	6.2		2.5		0.1		8.8
Total short-term debt and letters of credit	162.3		17.3		40.1		219.7
Remaining availability as of April 24, 2017	$	137.7	$	432.7	$	34.9	$	605.3
Invested cash as of April 24, 2017	$	1.5	$	—	$	—	$	1.5

In addition to the above, PNMR had $30.3 million of letters of credit outstanding under the JPM LOC Facility. The above table excludes intercompany debt. As of April 24, 2017, TNMP had intercompany borrowings from PNMR of $5.0 million. The remaining availability under the revolving credit facilities at any point in time varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures.

PNMR can offer new shares of common stock through the PNM Resources Direct Plan under a SEC shelf registration statement that expires in August 2018. PNM has a shelf registration statement for up to $250.0 million of senior unsecured notes that expires in May 2017.

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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 2016 Annual Reports on Form 10-K, as well as Note 5.

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 2016 Annual Reports on Form 10-K.

Contingent Provisions of Certain Obligations

As discussed in the 2016 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.

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, 2017		December 31, 2016
PNMR
PNMR common equity	41.3	%	41.1	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	58.4	%	58.6	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	46.3	%	46.0	%
Preferred stock	0.4	%	0.4	%
Long-term debt	53.3	%	53.6	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	58.4	%	58.5	%
Long-term debt	41.6	%	41.5	%
Total capitalization	100.0	%	100.0	%

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OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In 2016, GHG associated with PNM’s interests in its generating plants included approximately 6.6 million metric tons of CO₂, which comprises the vast majority of PNM’s GHG.  By comparison, the total GHG in the United States in 2015, the latest year for which EPA has published this data, were approximately 6.6 billion metric tons, of which approximately 5.4 billion metric tons were CO₂. 

PNM has several programs underway to reduce or offset GHG from its resource portfolio, thereby reducing its exposure to climate change regulation. See Note 12. PNM owns utility-scale solar generation with a total generation capacity of 107 MW. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and, since January 2015, has purchased the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW. PNM has a 20-year PPA for the output of Lightning Dock Geothermal, which began providing power to PNM in January 2014. The current capacity of the geothermal facility is 4 MW. Additionally, PNM has a customer distributed solar generation program that represented 66.8 MW at March 31, 2017. PNM’s distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 136 GWh. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a budget of $26.0 million for the 2017 program year. PNM estimates these programs saved approximately 82 GWh of electricity in 2016. Over the next 18 years, PNM projects energy efficiency and load management programs will provide the equivalent of approximately 9,000 GWh of electricity, which will avoid at least 5.5 million metric tons of CO₂ based upon projected emissions from PNM’s system-wide resources. These estimates are subject to change because of the uncertainty of many of the underlying variables, including changes in demand for electricity, and complex relationships between those variables.

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

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

As of December 31, 2016, approximately 70.7% of PNM’s generating capacity, including resources owned, leased, and under PPAs, all of which is located within the United States, consisted of coal or gas-fired generation that produces GHG. Based on current forecasts, the Company does not expect its output of GHG from existing sources to increase significantly in the near-term. Many factors affect the amount of GHG emitted. For example, if new natural gas-fired generation resources are added to meet increased load as anticipated in PNM’s 2014 IRP, GHG would be incrementally increased. In addition, plant performance could impact the amount of GHG emitted. 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. As described in Note 11, PNM received approval for the December 31, 2017 shutdown of SJGS Units 2 and 3 as part of its strategy to address the regional haze requirements of the CAA. The shutdown of Units 2 and 3 would result in a reduction of GHG for the entire station of approximately 50%, including a reduction of approximately 28% for the Company’s ownership interests.

Because of PNM’s dependence on fossil-fueled generation, legislation or regulation that imposes a limit or cost on GHG could impact the cost at which electricity is produced. While PNM expects to recover any such costs through rates, the timing and outcome of proceedings for cost recovery are uncertain. In addition, to the extent that any additional costs are recovered through rates, customers may reduce their usage, relocate facilities to other areas with lower energy costs, or take other actions that ultimately will adversely impact PNM.

PNM’s generating stations are located in the arid southwest. Access to water for cooling for some of these facilities is critical to continued operations. Forecasts for the impacts of climate change on water supply in the southwest range from reduced

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precipitation to changes in the timing of precipitation. In either case, PNM’s facilities requiring water for cooling will need to mitigate the impacts of climate change through adaptive measures. Current measures employed by PNM generating stations such as air cooling, use of grey water, improved reservoir operations, and shortage sharing arrangements with other water users will continue to be important to sustain operations.

PNM’s service areas occasionally experience periodic high winds, forest fires, and severe thunderstorms. TNMP has operations in the Gulf Coast area of Texas, which experiences periodic hurricanes and drought conditions. In addition to potentially causing physical damage to Company-owned facilities, which disrupts the ability to transmit and/or distribute energy, weather and other events of nature can temporarily reduce customers’ usage and demand for energy.

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

EPA Regulation

In April 2007, the US Supreme Court held that EPA has the authority to regulate GHG under the CAA.  This decision heightened the importance of this issue for the energy industry.  In December 2009, EPA released its endangerment finding stating that the atmospheric concentrations of six key greenhouse gases (CO₂, methane, nitrous oxides, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride) endanger the public health and welfare of current and future generations. In May 2010, EPA released the final PSD and Title V Greenhouse Gas Tailoring Rule (the “Tailoring Rule”) to address GHG from stationary sources under the CAA permitting programs. The purpose of the rule was to “tailor” the applicability of two programs, PSD and Title V operating permit programs, to avoid impacting millions of small GHG emitters. The rule focused on the largest sources of GHG, including fossil-fueled electric generating units. This program covered the construction of new emission units that emit GHG of at least 100,000 tons per year in CO₂ equivalents (even if PSD is not triggered for other pollutants). In addition, modifications at existing major-emitting facilities that increase GHG by at least 75,000 tons per year in CO₂ equivalents would be subject to PSD permitting requirements, even if they did not significantly increase emissions of any other pollutant. As a result, PNM’s fossil-fueled generating plants were more likely to trigger PSD permitting requirements because of the magnitude of GHG. However, as discussed below, a court case in 2014 now limits the extent of the Tailoring Rule.

On June 26, 2012, the DC Circuit rejected challenges to EPA’s 2009 GHG endangerment finding, GHG standards for light-duty vehicles, PSD Interpretive Memorandum (EPA’s so-called GHG “Timing Rule”), and the Tailoring Rule. The court found that EPA’s endangerment finding and its light-duty vehicle rule “are neither arbitrary nor capricious,” that “EPA’s interpretation of the governing CAA provisions is unambiguously correct,” and that “no petitioner has standing to challenge the Timing and Tailoring Rules.” On October 15, 2013, the US Supreme Court granted a petition for a Writ of Certiorari regarding the permitting of stationary sources that emit GHG. The US Supreme Court limited its review to the question of whether EPA’s determination that regulation of GHG from motor vehicles required EPA to regulate stationary sources under the PSD and Title V permitting programs. The petitioners argued that EPA’s determination was unlawful as it violates Congressional intent.

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

On June 25, 2013, former President Obama announced his Climate Action Plan which outlined how his administration planned to cut GHG in the United States, prepare the country for the impacts of climate change, and lead international efforts to combat and prepare for global warming. The plan proposed actions that would lead to the reduction of GHG by 17% below 2005

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levels by 2020. The former President also issued a Presidential Memorandum to EPA to continue development of the GHG NSPS regulations for electric generators. The Presidential Memorandum established a timeline for the proposal and issuance of a GHG NSPS for new sources under section 111(b) of the CAA and a timeline for the proposal and final rule for developing carbon pollution standards, regulations, or guidelines for GHG reductions from existing sources under Section 111(d) of the CAA. The Presidential Memorandum further directed EPA to allow the use of “market-based instruments” and “other regulatory flexibilities” to ensure standards will allow for continued reliance on a range of energy sources and technologies, and that the standards are developed and implemented in a manner that provides for reliable and affordable energy. The Presidential Memorandum required EPA to undertake the rulemaking through direct engagement with states, “as they will play a central role in establishing and implementing standards for existing power plants,” and with utility leaders, labor leaders, non-governmental organizations, tribal officials, and other stakeholders.

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

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

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

The final Clean Power Plan rule changed significantly in structure from the proposed rule that was released in June 2014. Changes include delaying the first compliance date by two years from 2020 to 2022; adopting a new approach to calculating the emission targets which resulted in different state goals than those originally proposed; adding a reliability safety valve; and proposing rewards for early reductions. The rule establishes two numeric “emission standards” – one for “fossil-steam” units (coal- and oil-fired units) and one for natural gas-fired units (combined cycle only). The emission standards are based on emission reduction opportunities that EPA deemed achievable using technical assumptions for three “building blocks”: efficiency improvements at coal-fired EGUs, displacement of affected EGUs with renewable energy, and displacement of coal-fired generation with natural gas-fired generation. The final standards are 1,305 lbs/MWh for fossil-steam units and 771 lbs/MWh for gas units, both of which phase in over the period 2022-2030. To facilitate implementation, EPA converted the emission standards into state goals. Each state’s goal reflects the average state-wide emission rate that all of the state’s affected EGUs would meet in the aggregate if each one achieved the emission standards alone based upon a weighted average of each state’s unique mix of affected units.

Under the final rule, the Clean Power Plan compliance schedule required states to make initial plan submissions to EPA by September 6, 2016. EPA could then choose to grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension were to submit an update to EPA in 2017 and final plans by September 2018. States not requesting an extension were to submit their final plans by September 2016. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide, but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. Plans using state measures may only be used with mass-based goals and must include “backstop”

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federally enforceable standards for EGUs that will become effective if the state measures fail to achieve the expected level of emission reductions.

The Clean Power Plan also proposes a Clean Energy Incentive Program (“CEIP”) designed to award credits for early development of certain renewable energy and energy efficiency programs that displace fossil generation in 2020 and 2021 prior to the compliance obligation taking effect in 2022. On June 30, 2016, EPA published proposed design details of the CEIP. Comments were due to EPA on November 1, 2016. In addition, the Clean Power Plan contains a reliability safety valve for individual power plants. The reliability safety valve allows for a 90-day relief from CO₂ emissions limits if generating units need to continue to operate and release excess emissions during emergencies that could compromise electric system reliability.

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

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

On January 26, 2016, 29 states and state agencies filed a petition to the US Supreme Court asking the court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court granted the applications to stay the Clean Power Plan pending judicial review of the rule.  The US Supreme Court issued a one-page order that stated, “The EPA rule to have states cut power sector carbon dioxide (CO₂) emissions 32% by 2030 is stayed pending disposition of the applicants’ petitions for review in the United States Court of Appeals for the District of Columbia Circuit.” The vote was 5-4 among the US Supreme Court Justices. The decision means the Clean Power Plan is not in effect and states are not obliged to comply with its requirements. The DC Circuit heard oral arguments on the merits of the states’ case on September 27, 2016. The arguments were made in front of a 10-judge panel. There is no mandatory deadline for the DC Circuit to make a decision on the case. The stay will remain in effect pending US Supreme Court review if such review is sought.

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 the EPA to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the New Source Performance Standards for GHG emissions from new, reconstructed or modified electric utilities, (3) the Proposed Clean Power Plan Model Trading Rules, (4) the Legal Memorandum supporting the Clean Power Plan, and (5) the New Source Performance Standards for Oil & Natural Gas Sector. The Order disbands the Interagency Working Group on the Social Cost of Greenhouse Gases, rescinds all documents developed by that group as “no longer representative of government policy,” and directs agencies to evaluate costs consistent with a 2003 memorandum from the Office of Management and Budget. In addition, the order repeals the moratorium on new leases for coal mined from federal lands. Finally, it requires EPA and the Department of Justice to work with the US Attorney General to put on hold any litigation regarding any of the regulations the order addresses. Subsequently, on March 28, 2017, EPA and the Department of Justice filed a motion in the DC Circuit seeking to hold the Clean Power Plan case in abeyance. The court has not yet acted on the motion.

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PNM is unable to predict the impact to the Company of this Executive Order. It is uncertain the direction EPA will undertake with respect to suspending, revising or rescinding these rules. If the Clean Power Plan prevails in some form after a formal notice and comment rulemaking, or a future regulation limiting GHG from fossil electric generating units is adopted, such regulations would impact PNM’s existing and future fossil-fueled EGUs. The existing Carbon Pollution Standards covering new sources will also impact PNM’s generation fleet although that rule is also under review by EPA. Impacts could result in requirements for investments in additional renewables and energy efficiency programs, efficiency improvements, and/or control technologies at PNM’s fossil-fueled EGUs. There are limited efficiency enhancement measures that may be available to a subset of the existing EGUs; however, such measures would provide only marginal GHG improvements. The only emission control technology for GHG reduction from coal and gas-fired power plants is carbon capture and sequestration, which is not yet a commercially demonstrated technology. Additional GHG control technologies for existing EGUs may become viable in the future. The costs of purchasing carbon credits or allowances, making improvements, or installing new technology could impact the economic viability of some plants. PNM estimates that implementation of the BART plan at SJGS that required the installation of SNCRs on Units 1 and 4 by early 2016, which has been completed, and the retirement of SJGS Units 2 and 3 by the end of 2017 as described in Note 11, should provide a significant step for New Mexico to meet its ultimate compliance with future regulations limiting GHG. PNM is unable to predict the impact on its fossil-fueled generation.

Federal Legislation

Prospects for enactment in Congress of legislation imposing a new or enhanced regulatory program to address climate change are unlikely in 2017.  EPA continues to be the primary vehicle for GHG regulation in the near future, especially for coal-fired EGUs.

State and Regional Activity

Pursuant to New Mexico law, each utility must submit an IRP to the NMPRC every three years to evaluate renewable energy, energy efficiency, load management, distributed generation, and conventional supply-side resources on a consistent and comparable basis.  The IRP is required to take into consideration risk and uncertainty of fuel supply, price volatility, and costs of anticipated environmental regulations when evaluating resource options to meet supply needs of the utility’s customers.  The NMPRC requires that New Mexico utilities factor a standardized cost of carbon emissions into their IRPs using prices ranging between $8 and $40 per metric ton of CO₂ emitted and escalating these costs by 2.5% per year.  Under the NMPRC order, each utility must analyze these standardized prices as projected operating costs.  Reflecting the developing nature of this issue, the NMPRC order states that these prices may be changed in the future to account for additional information or changed circumstances.  Although these prices may not reflect the costs that ultimately will be incurred, PNM is required to use these prices for purposes of its IRP.  PNM’s 2014 IRP filed with the NMPRC on July 1, 2014 showed that consideration of carbon emissions costs impacted the projected in-service dates of some of the identified resources.  PNM has begun its process for the 2017 IRP that is to be filed by July 3, 2017. In the 2017 IRP, PNM will present resource portfolio plans for scenarios that assume SJGS will operate beyond the end of the current coal supply agreement that runs through June 30, 2022 and for scenarios that assume SJGS will cease operations by the end of 2022. PNM has been meeting with customers and stakeholders as part of a public advisory process since June 2016. On April 20, 2017, PNM released a draft of the 2017 IRP. The key findings include that retiring SJGS in 2022 would provide long-term cost benefits to PNM’s customers and PNM exiting its ownership interest in Four Corners in 2031 would also save customers money. The materials presented in the process are available at www.pnm.com\irp.

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

International Accords

The United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was negotiated at the 1992 United Nations Conference on Environment and Development (informally known as the Earth Summit) and entered into force in March 1994.  The objective of the treaty is to “stabilize greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.”  Parties to the UNFCCC, including the United States, have been meeting annually in Conferences of the Parties (“COP”) to assess progress in meeting the objectives of the UNFCCC.  This assessment process led to the negotiation of the Kyoto Protocol in the mid-1990s.  The Kyoto Protocol, which was agreed to in 1997 and established legally binding obligations for developed countries to reduce their GHG, was never ratified by the United States.  PNM monitors the proceedings of the UNFCCC, including the annual COP meetings, to determine potential impacts to its business activities.  At the COP meeting in 2011, participating nations, including the United States, agreed to negotiate by 2015 an international agreement involving commitments by all nations to begin reducing carbon

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emissions by 2020.  On December 12, 2015, the Paris Agreement was finalized during the 2015 COP. The agreement, which was agreed to by more than 190 nations, requires that countries submit Nationally Determined Contributions (“NDCs”). NDCs reflect national targets and actions that arise out of national policies, and elements relating to oversight, guidance and coordination of actions to reduce emissions by all countries.  In November 2014, former President Obama announced the United States’ commitment to reduce GHG, on an economy-wide basis, by 26%-28% from 2005 levels by the year 2025. The United States NDC is part of an overall effort by the Obama administration to have the United States achieve economy-wide reductions of around 80% by 2050.  As part of the process for developing the global climate agreement, the United States set forth this reduction commitment in its intended NDC.  As part of the Paris Agreement, 189 nations offered intended NDCs, including the United States and the European Union.  Thresholds for the number of countries necessary to ratify or accede to the Paris Agreement and total global GHG percentage were achieved on October 5, 2016, and the Paris Agreement entered into force on November 4, 2016. To date, 143 countries have ratified the Paris Agreement. PNM will continue to monitor the United States’ participation in international accords.  The Obama administration’s GHG reduction target for the electric utility industry is a key element of its NDC and is based on EPA’s final GHG regulations for new, existing, and modified and reconstructed sources. With the change in federal administrations, the United States’ continued participation in the Paris Agreement is now uncertain. PNM believes that implementation of the BART plan for SJGS (Note 11) should provide a significant step for New Mexico to comply with the Clean Power Plan, should it prevail, or other GHG reduction requirements.

Assessment of Legislative/Regulatory Impacts

The Company has assessed, and continues to assess, the impacts of climate change legislation or regulation on its business.  This assessment is ongoing and future changes arising out of the legislative or regulatory process could impact the assessment significantly.  PNM’s assessment includes assumptions regarding specific GHG limits; the timing of implementation of these limits; the possibility of a market-based trading program, including the associated costs and the availability of emission credits or allowances; the development of emission reduction and/or renewable energy technologies; and provisions for cost containment. Moreover, the assessment assumes various market reactions such as the price of coal and gas and regional plant economics.  These 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.  In turn, these consequences could lead to increased costs to customers and affect results of operations, cash flows, and financial condition if the incurred costs are not fully recovered through regulated rates. Higher rates could also contribute to reduced usage of electricity.  PNM’s assessment process is too preliminary and speculative at this time for a meaningful prediction of financial impact.

Transmission Issues

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

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

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

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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. 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 2016 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, 2017, there have been no significant changes with regard to the critical accounting policies disclosed in PNMR’s, PNM’s, and TNMP’s 2016 Annual Reports on Forms 10-K. The policies disclosed included unbilled revenues, regulatory accounting, impairments, decommissioning and reclamation costs, pension and other postretirement benefits, accounting for contingencies, income taxes, and market risk.

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

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

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

• Uncertainty surrounding the status of PNM’s participation in jointly-owned generation projects, including the scheduled expiration of the operational and fuel supply agreements for SJGS, as well as the 2018 required NMPRC filing to determine the extent to which SJGS should continue serving PNM’s retail customers beyond mid-2022 and the outcome of the related analysis undertaken in connection with PNM’s 2017 IRP

• The Company’s ability to access the financial markets in order to provide financing to repay or refinance debt as it comes due, as well as for ongoing operations and construction expenditures, including disruptions in the capital or credit markets, actions by ratings agencies, and fluctuations in interest rates, including any negative impacts that could result from the ultimate outcome in PNM’s NM 2015 Rate Case, including appeals, and PNM’s NM 2016 Rate Case

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

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

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

• Uncertainty regarding the requirements and related costs of decommissioning power plants and reclamation of coal mines supplying certain power plants, as well as the ability to recover those costs from customers, including the potential impacts of the order in the NM 2015 Rate Case, appeals of that order, the ultimate outcome of PNM’s NM 2016 Rate Case, and PNM’s 2017 IRP

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

• The performance of generating units, transmission systems, and distribution systems, which could be negatively affected by operational issues, fuel quality, unplanned outages, extreme weather conditions, terrorism, cybersecurity breaches, and other catastrophic events

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

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

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

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

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

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

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

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

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

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

• Changes in applicable accounting principles or policies

Any material changes to risk factors occurring after the filing of PNMR’s, PNM’s, and TNMP’s 2016 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 related to the operations of PNM and TNMP and reflects PNMR’s commitment to do business in an ethical, open, and transparent manner.

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

• Corporate Governance Principles

• Code of Ethics (Do the Right Thing – Principles of Business Conduct)

• Charters of the Audit and Ethics Committee, Nominating and Governance Committee, Compensation and Human Resources Committee, and Finance Committee

The Company will post amendments to or waivers from its code of ethics (to the extent applicable to the Company’s executive officers and directors) on its website.

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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 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, 2017 and the year ended December 31, 2016, the Company had no commodity derivative instruments designated as cash flow hedging instruments.

Commodity contracts, other than those that do not meet the definition of a derivative under GAAP and those derivatives designated as normal purchases and normal sales, 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,
	2017			2016
Economic Hedges	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	2,885		$	4,576
Amount realized on contracts delivered during period	(2,007		)	(1,105		)
Changes in fair value	3,352			2,539
Net mark-to-market change recorded in earnings	1,345			1,434
Net change recorded as regulatory assets and liabilities	(4		)	(216		)
Net fair value at end of period	$	4,226		$	5,794

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The following table provides the maturity of the net assets (liabilities), giving an indication of when these mark-to-market amounts will settle and generate (use) cash.

Fair Value of Mark-to-Market Instruments at March 31, 2017

	Settlement Dates
	2017		2018
	(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—
Prices provided by other external sources	4,226		—
Prices based on models and other valuations	—		—
Total	$	4,226	$	—

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

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

PNM measures VaR for the positions in its wholesale portfolio (not covered by the FPPAC). For the three months ended March 31, 2017, the high, low, and average VaR amounts were $0.7 million, $0.4 million, and $0.6 million. For the year ended December 31, 2016, the high, low, and average VaR amounts were $1.3 million, $0.3 million, and $0.6 million. At March 31, 2017 and December 31, 2016, the VaR amounts for the PNM wholesale portfolio were $0.5 million and $0.6 million.

The VaR represents an estimate of the potential gains or losses that could be recognized on the Company’s portfolios, subject to market risk, given current volatility in the market, and is not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market prices, operating exposures, and the timing thereof, as well as changes to the underlying portfolios during the year. VaR limits were not exceeded during the three months ended March 31, 2017 or the year ended December 31, 2016.

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, 2017

Rating (1)	Credit Risk Exposure(2)		Number of Counter-parties >10%	Net Exposure of Counter-parties >10%
	(Dollars in thousands)
External ratings:
Investment grade	$	2,994	—	$	—
Non-investment grade	104		—	—
Split ratings	232
Internal ratings:
Investment grade	2,453		1	2,342
Non-investment grade	4,695		1	4,416
Total	$	10,478		$	6,758

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

⁽²⁾  The Credit Risk Exposure is the gross credit exposure, including long-term contracts (other than firm-requirements wholesale customers), forward sales, and short-term sales. The exposure captures the amounts from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses. Gross exposures can be offset according to legally enforceable netting arrangements, but are not reduced by posted credit collateral. At March 31, 2017, PNMR held $0.1 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of March 31, 2017 was $4.4 million.

As discussed in Note 11, PNMR’s subsidiary, NM Capital, entered into the Westmoreland Loan to facilitate the acquisition of SJCC by WSJ, a subsidiary of Westmoreland, and PNMR has arranged for letters of credit to be issued to support the coal mining operations of SJCC. PNMR is exposed to credit risk under these arrangements in the event of default by WSJ. As of April 24, 2017, remaining required principal payments under the Westmoreland Loan are $28.8 million in 2017, $3.6 million in 2018, $8.6 million in 2019, $23.3 million in 2020, and $21.1 million in 2021. As of April 24, 2017, $11.8 million was held in a SJCC restricted bank account that will be used solely to make the May 2, 2017 scheduled principal payment of $9.6 million and interest on the Westmoreland Loan. In addition, the Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations, the value of which PNMR believes approximates the amount outstanding under the Westmoreland Loan.  Furthermore, PNMR considers the possibility of loss under the letters of credit to be remote as discussed in Note 5. Accordingly, PNMR does consider its credit risk under these arrangements to be material.

Other investments have no significant counterparty credit risk.

Interest Rate Risk

The majority of the Company’s long-term debt is fixed-rate debt and does not expose earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of PNMR’s consolidated long-term debt instruments would increase by 1.6%, or $40.4 million, if interest rates were to decline by 50 basis points from their levels at March 31, 2017. In general, an increase in fair value would impact earnings and cash flows to the extent not recoverable in rates if all or a portion of debt instruments were acquired in the open market prior to their maturity. At April 24, 2017, PNMR, PNM, and TNMP had short-term debt outstanding of $156.1 million, $7.8 million, and $40.0 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, and $75.0 million for TNMP. PNM also had borrowings of $7.0 million under the $50.0 million PNM New Mexico Credit Facility at April 24, 2017. The revolving credit facilities, the PNM New Mexico Credit Facility, the $150.0 million PNMR 2015 Term Loan Agreement, the $100.0 million PNMR 2016 One-Year Term Loan Agreement, the $100.0 million PNMR 2016 Two-Year Term Loan Agreement, the $175.0 million PNM 2016 Term Loan Agreement, and the $125.0 million BTMU Term Loan Agreement bear interest at variable

112

rates. On April 24, 2017, interest rates on borrowings averaged 2.24% for the PNMR Revolving Credit Facility, 1.89% for the PNMR 2015 Term Loan Agreement, 3.79% for the BTMU Term Loan Agreement, 1.84% for the PNMR 2016 One-Year Term Loan Agreement, 1.94% for the PNMR 2016 Two-Year Term Loan Agreement, 2.12% for the PNM Revolving Credit Facility, 2.13% for the PNM New Mexico Credit Facility, 1.59% for the PNM 2016 Term Loan Agreement, and 1.99% for the TNMP Revolving Credit Facility. The Company is exposed to interest rate risk to the extent of future increases in variable interest rates. However, as discussed in Note 9, PNMR has entered into hedging arrangements to effectively establish fixed interest rates on the PNMR 2015 Term Loan Agreement and $50.0 million of short-term variable rate debt.

The investments held by PNM in trusts for decommissioning and reclamation had an estimated fair value of $286.1 million at March 31, 2017, of which 37.2% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at March 31, 2017, the decrease in the fair value of the fixed-rate securities would be 3.9%, or $4.2 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.

Equity Market Risk

The investments held by PNM in trusts for decommissioning and reclamation include certain equity securities at March 31, 2017. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 60.0% of the securities held by the trusts as of March 31, 2017. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $17.2 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

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, 2017 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.

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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 Clean Air Act – Regional Haze – SJGS

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

• WEG v. OSM NEPA Lawsuit

• Navajo Nation Environmental Issues

• Santa Fe Generating Station

• 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 – Renewable Energy Rider

• PNM – Energy Efficiency and Load Management

• PNM – Integrated Resource Plans

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

• PNM – Application for Certificate of Convenience and Necessity

• PNM – Advanced Metering Infrastructure Application

• PNM – Hazard Sharing Agreement

• TNMP – Transmission Cost of Service Rates

• TNMP – Competition Transition Charge Compliance Filing

See also Climate Change Issues under Other Issues Facing the Company in MD&A. The third paragraph under State and Regional Activity is incorporated in this item by reference.

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, 2016.

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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 February 26, 2015 (incorporated by reference to Exhibit 3.4 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2014)
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)
10.1	PNMR	2017 Officer Annual Incentive Plan dated March 29, 2017
10.2	PNMR	2017 Long-Term Incentive Plan dated March 31, 2017
12.1	PNMR	Ratio of Earnings to Fixed Charges
12.2	PNM	Ratio of Earnings to Fixed Charges
12.3	TNMP	Ratio of Earnings to Fixed Charges
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

115

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
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:	April 28, 2017	/s/ Joseph D. Tarry
		Joseph D. Tarry
		Vice President, Finance and Controller
		(Officer duly authorized to sign this report)

117

EX-10.1

EXHIBIT 10.1

PNM RESOURCES, INC.

2017 OFFICER ANNUAL INCENTIVE PLAN

Introduction

PNM Resources, Inc. (the “Company” or “PNMR”) has adopted this 2017 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”). In the case of Officers who are Covered Employees as defined in the PEP, the Awards also are 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 has the title of Chief Executive Officer, Executive Vice President, Senior Vice President or Vice President and 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 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, 2017 and will end on December 31, 2017.

An Officer’s Award will equal the Officer’s share of the Incentive EPS Award Pool described below. If 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; however, the Officer will receive the smaller amount.

An Officer’s share of the Incentive EPS Award Pool or the Performance Award Pool (individually, 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 January 1, 2017. 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 $1.77 but is less than $1.82), 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 Pools

A Corporate Goals Scorecard and Business Area Goals Scorecard listing each performance measure established by the Committee will be maintained by the PNM Resources, Inc. Management Systems group. 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 and Business Area Goals Scorecards;

2

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

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 February 2018, the Committee will determine and certify the level of Awards, if any, payable for the Performance Period in the manner described above. The final Awards calculation and recommendation to the Committee by management will be reviewed and certified by the Vice-President, Human Resources; Director, Audit and Cost of Service; Director, Customer Services (who is oversees the Management Systems group); and Vice President, Finance and Controller, respectively. The independent directors of the Board then will approve the Chief Executive Officer’s Award and the Committee will approve the Awards for all other Officers. To the extent Awards are payable under the Plan, the Company will make the payment on or before March 15, 2018 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. Notwithstanding the foregoing, the Committee’s authority to increase Awards made pursuant to this Plan does not apply to Covered Employees.

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

3

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.

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, including a same sex spouse, or the estate of an unmarried Officer.

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.

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

4

month will count as a full month.) 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, 2018.

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 any Clawback Policy that may be adopted by the Company. 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: March 29    , 2017

5

ATTACHMENT A

Incentive EPS Table

(Table 1)

	Incentive EPS1
No Award	Less than $1.77
Threshold	Greater than or equal to $1.77 and less than $1.82
Target	Greater than or equal to $1.82 and less than $1.90
Maximum	Greater than or equal to $1.90

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	55%	110%	220%
EVP	35%	70%	140%
SVP	27.5%	55%	110%
Vice-Presidents	20%	40%	80%

___________________________

¹Equals PNMR’s diluted EPS for the fiscal year ending December  31, 2017 calculated in accordance with Generally Accepted Accounting Principles and reported in the Company’s Form 10-K for PNM Resources adjusted to exclude the following items: (1) mark-to-market impact of economic hedges, (2) regulatory disallowances, (3) change in unrealized impacts of plant decommissioning and coal mine reclamation trust securities, (4) gains or losses on reacquired debt, (5) goodwill or other intangible asset impairments, (6) impacts of acquisition and disposition activities, including but not limited to pension expense or income associated with PNM’s 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 24, 2017, (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 due to changes in state or federal tax law, (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 retired generating stations, (11) costs associated with process improvement initiatives, and (12) changes to the liabilities associated with mine reclamation costs that are attributable to (a) changes in the discount rate used to measure those liabilities, (b) an early retirement of generating stations or (c) action taken by the New Mexico Public Regulation Commission.

A-1

EX-10.2

EXHIBIT 10.2

PNM RESOURCES, INC.
2017 LONG-TERM INCENTIVE PLAN

Introduction

• The 2017 Long-Term Incentive Plan (the “Plan” or the “2017 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 has the title of Chief Executive Officer, Executive Vice President, Senior Vice President or Vice President and 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 Company’s Compensation and Human Resources Committee (the “Committee”).

Performance Period

• The Performance Period began on January 1, 2017 and will end on December 31, 2019.

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 a an Earnings Growth Goal, 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 Company’s Board of Directors (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 3, 2017 (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 Separates from Service in the second half of the Performance Period (in other words, between July 1, 2018 and December 31, 2019) 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 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 the PEP. The prorated Award then will be paid at the same time as Awards are paid to other participants in the Plan.

2

• 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 pro-rata 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 pro-rata Performance Share Award to the new Officer on such terms and conditions as the Committee deems to be appropriate.

• All Performance Share Awards payable to Officers who are Covered Employees for the Company’s tax year that coincides with the end of the Performance Period are intended to qualify as Performance-Based Awards granted pursuant to Section 10 of the PEP. As a result, all such Awards are 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 any Clawback Policy that may be adopted by the Company. 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: March 31    , 2017

3

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 40% of the Threshold, Target or Maximum Award as determined in accordance with the Performance Share Award Opportunity Table.	At least 3%, but less than 4%	At least 4%, but less than 8%	At least 8%
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 30% 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 95th percentile	Greater than or equal to the 95th 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 30% of the Threshold, Target or Maximum Award as determined in accordance with the Performance Share Award Opportunity Table.	At least 15%, but less than 16%	At least 16%, but less than 18%	At least 18%

_______________________

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 period 2017 to 2019, 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, 2019 by the Earnings Per Share (as defined below) for the year ended December  31, 2016. 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: [(2019 Earnings Per Share/2016 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, 2016 and 2019 calculated in accordance with Generally Accepted Accounting Principles and reported in the Company’s Form 10-K for PNM Resources adjusted to exclude the following items: (1) mark-to-market impact of economic hedges, (2) regulatory disallowances, (3) change in unrealized impacts of plant decommissioning and coal mine reclamation trust securities, (4) gains or losses on reacquired debt, (5) goodwill or other intangible asset impairments, (6) impacts of acquisition and disposition activities, including but not limited to pension expense or income associated with PNM’s 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 24, 2017, (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 due to changes in state or federal tax law, (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 that are attributable 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 S & P 400 Mid-Cap Utility Index.

For this purpose, the Total Shareholder Return of the Company and the other utilities included in the 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, 2019, divided by PNMR’s total debt outstanding (including any long-term leases and unfunded pension plan obligations) 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, and (5) 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 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.

A-2

ATTACHMENT B

Performance Share Award Opportunity Table

Officer Level	Threshold Award	Target Award	Maximum Award
CEO	Performance Shares = 80.5% of base salary	Performance Shares = 161% of base salary	Performance Shares = 322% of base salary
EVP	Performance Shares = 38.5% of base salary	Performance Shares = 77% of base salary	Performance Shares = 154% 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

B-1

ATTACHMENT C

Time-Vested Restricted Stock Rights Award Opportunity Table

Officer Level	Award
CEO	Restricted Stock Rights = 69% of base salary
EVP	Restricted Stock Rights = 33% of base salary
SVP	Restricted Stock Rights = 25.5% of base salary
VP	Restricted Stock Rights = 15% of base salary

C-1

ATTACHMENT D

2017 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 Company’s Compensation and Human Resources Committee (the “Committee”) has developed the PNM Resources, Inc. 2017 Long-Term Incentive Plan (the “Plan” or the “2017 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 2017 Plan are made pursuant to the PEP and are subject to the provisions of the PEP. In addition, all of the Awards under the 2017 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, within 75 days following the end of the Performance Period. The Committee then will certify and submit its determinations with respect to the Earnings Growth, Relative TSR and FFO/Debt Ratio and the number of Performance Shares to which an Officer is entitled 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, as a 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.

(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.

D-1

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, 2021; (ii) an additional 34% of the time-vested Restricted Stock Rights will vest on March 7, 2022; and (iii) the final 33% of the time-vested Restricted Stock Rights will vest on March 7, 2023 (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)    The delivery of the time-vested Restricted Stock Rights may be delayed to the extent necessary to comply with Federal securities laws.

(5)    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,

D-2

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.

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 PEPs.

6.    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.

6.    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.

7.    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.

8.    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-12.1

Exhibit 12.1
PNM RESOURCES, INC. AND SUBSIDIARIES
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Three Months Ended			Year Ended December 31,
	March 31, 2017			2016				2015				2014				2013				2012
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	31,754		$	129,592			$	117,932			$	117,337			$	118,880			$	125,379
Amortization of debt premium, discount, and expenses	949			3,779				3,575				4,194				3,716				4,023
Estimated interest factor of lease rental charges	646			2,747				3,298				4,686				5,847				5,585
Preferred dividend requirements of subsidiary	186			781				784				809				800				769
Total Fixed Charges	$	33,535		$	136,899			$	125,589			$	127,026			$	129,243			$	135,756
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes and non-controlling interest	$	37,221		$	195,174			$	46,153			$	200,647			$	175,069			$	175,035
Fixed charges as above	33,535			136,899				125,589				127,026				129,243				135,756
Interest capitalized	(1,704		)	(7,964		)		(9,753		)		(6,256		)		(5,209		)		(5,432		)
Non-controlling interest in earnings of Valencia	(3,452		)	(14,519		)		(14,910		)		(14,127		)		(14,521		)		(14,050		)
Preferred dividend requirements of subsidiary	(186		)	(781		)		(784		)		(809		)		(800		)		(769		)
Earnings Available for Fixed Charges	$	65,414		$	308,809			$	146,295			$	306,481			$	283,782			$	290,540
Ratio of Earnings to Fixed Charges	1.95			2.26			1	1.16			2	2.41			3	2.20			4	2.14
1  Earnings from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2016 includes a pre-tax loss of $15.0 million due to the write-off of regulatory disallowances and restructuring costs at PNM. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.37 for 2016.
2  Earnings from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2015 includes a pre-tax loss of $167.5 million due to the write-off of regulatory disallowances and restructuring costs at PNM. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.50 for 2015.
3  Earnings from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2014 includes a pre-tax loss of $1.1 million due to the write-off of regulatory disallowances at PNM. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.42 for 2014.
4  Earnings from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2013 includes a pre-tax loss of $12.2 million due to the write-off of regulatory disallowances at PNM. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.29 for 2013.

EX-12.2

Exhibit 12.2
PUBLIC SERVICE COMPANY OF NEW MEXICO
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Three Months Ended			Year Ended December 31,
	March 31, 2017			2016				2015				2014				2013				2012
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	21,551		$	89,502			$	84,695			$	79,834			$	79,769			$	82,864
Amortization of debt premium, discount and expenses	541			2,312				1,978				1,944				1,879				1,818
Estimated interest factor of lease rental charges	303			1,217				1,532				2,541				3,732				3,743
Total Fixed Charges	$	22,395		$	93,031			$	88,205			$	84,319			$	85,380			$	88,425
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	27,818		$	132,860			$	(13,082	)		$	154,086			$	151,480			$	156,314
Fixed charges as above	22,395			93,031				88,205				84,319				85,380				88,425
Non-controlling interest in earnings of Valencia	(3,452		)	(14,519		)		(14,910		)		(14,127		)		(14,521		)		(14,050		)
Interest capitalized	(1,456		)	(6,094		)		(8,530		)		(5,211		)		(4,420		)		(4,314		)
Earnings Available for Fixed Charges	$	45,305		$	205,278			$	51,683			$	219,067			$	217,919			$	226,375
Ratio of Earnings to Fixed Charges	2.02			2.21			1	0.59			2	2.60			3	2.55			4	2.56
1 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2016 includes a pre-tax loss of $15.0 million due to the write-off of regulatory disallowances and restructuring costs. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.37 for 2016.
2 The shortfall in earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $36.5 million for the year ended December 31, 2015. Earnings (loss) from continuing operations before income taxes includes a pre-tax loss of $167.5 million due to the write-off of regulatory disallowances and restructuring costs. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.48 for 2015.
3 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2014 includes a pre-tax loss of $1.1 million due to the write-off of regulatory disallowances. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.61 for 2014.
4 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2013 includes a pre-tax loss of $12.2 million due to the write-off of regulatory disallowances. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.70 for 2013.

EX-12.3

Exhibit 12.3
TEXAS-NEW MEXICO POWER COMPANY
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Three Months Ended			Year Ended December 31,
	March 31, 2017			2016			2015			2014			2013			2012
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	6,929		$	27,698		$	25,875		$	24,941		$	24,481		$	26,233
Amortization of debt premium, discount and expenses	307			1,039			1,100			1,195			1,159			1,493
Estimated interest factor of lease rental charges	300			1,249			1,229			1,311			1,241			956
Total Fixed Charges	$	7,536		$	29,986		$	28,204		$	27,447		$	26,881		$	28,682
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes	$	11,293		$	65,508		$	66,088		$	60,330		$	46,711		$	42,099
Fixed charges as above	7,536			29,986			28,204			27,447			26,881			28,682
Interest capitalized	(156		)	(877		)	(593		)	(609		)	(361		)	(706		)
Earnings Available for Fixed Charges	$	18,673		$	94,617		$	93,699		$	87,168		$	73,231		$	70,075
Ratio of Earnings to Fixed Charges	2.48			3.16			3.32			3.18			2.72			2.44

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:	April 28, 2017	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:	April 28, 2017	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:	April 28, 2017	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:	April 28, 2017	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:	April 28, 2017	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:	April 28, 2017	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, 2017, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on April 28, 2017 (“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:	April 28, 2017	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, 2017, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on April 28, 2017 (“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:	April 28, 2017	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, 2017, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on April 28, 2017 (“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:	April 28, 2017	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, 2017	Apr. 24, 2017
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
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		79,653,624
Public Service Company of New Mexico
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, 2017	Mar. 31, 2016
Electric Operating Revenues	$ 330,178	$ 310,961
Operating Expenses:
Cost of energy	102,804	92,369
Administrative and general	47,532	47,109
Energy production costs	31,787	42,686
Regulatory disallowances and restructuring costs	0	774
Depreciation and amortization	56,383	49,829
Transmission and distribution costs	16,477	16,594
Taxes other than income taxes	19,235	20,092
Total operating expenses	274,218	269,453
Operating income	55,960	41,508
Other Income and Deductions:
Interest income	4,881	3,622
Gains on available-for-sale securities	6,661	6,218
Other income	4,902	4,264
Other (deductions)	(3,483)	(2,999)
Net other income and deductions	12,961	11,105
Interest Charges	31,700	31,491
Earnings before Income Taxes	37,221	21,122
Income Taxes	10,775	7,157
Net Earnings	26,446	13,965
(Earnings) Attributable to Valencia Non-controlling Interest	(3,452)	(3,287)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)
Net Earnings Attributable to PNMR	22,862	10,546
Net Earnings Available for PNM Common Stock	$ 22,862	$ 10,546
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)	$ 0.29	$ 0.13
Diluted (dollars per share)	0.29	0.13
Dividends Declared per Common Share (dollars per share)	$ 0.2425	$ 0.220
Public Service Company of New Mexico
Electric Operating Revenues	$ 251,558	$ 235,606
Operating Expenses:
Cost of energy	81,317	72,444
Administrative and general	43,047	42,028
Energy production costs	31,787	42,686
Regulatory disallowances and restructuring costs	0	774
Depreciation and amortization	36,016	31,864
Transmission and distribution costs	9,919	10,316
Taxes other than income taxes	11,141	12,197
Total operating expenses	213,227	212,309
Operating income	38,331	23,297
Other Income and Deductions:
Interest income	2,816	1,522
Gains on available-for-sale securities	6,661	6,218
Other income	3,843	3,387
Other (deductions)	(2,821)	(1,662)
Net other income and deductions	10,499	9,465
Interest Charges	21,012	21,591
Earnings before Income Taxes	27,818	11,171
Income Taxes	7,708	3,610
Net Earnings	20,110	7,561
(Earnings) Attributable to Valencia Non-controlling Interest	(3,452)	(3,287)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)
Net Earnings Attributable to PNMR	16,658	4,274
Net Earnings Available for PNM Common Stock	16,526	4,142
Texas-New Mexico Power Company
Electric Operating Revenues	78,620	75,355
Operating Expenses:
Cost of energy	21,487	19,925
Administrative and general	10,403	9,590
Depreciation and amortization	15,371	14,508
Transmission and distribution costs	6,558	6,278
Taxes other than income taxes	6,836	6,500
Total operating expenses	60,655	56,801
Operating income	17,965	18,554
Other Income and Deductions:
Other income	822	593
Other (deductions)	(90)	15
Net other income and deductions	732	608
Interest Charges	7,404	7,369
Earnings before Income Taxes	11,293	11,793
Income Taxes	3,689	4,337
Net Earnings Attributable to PNMR	$ 7,604	$ 7,456

XML

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Net Earnings	$ 26,446	$ 13,965
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	4,736	3,328
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(1,685)	(6,836)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience losses recognized as net periodic benefit cost, net of income tax expense (benefit)	987	839
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $72 and $503	(113)	(786)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(44) and $(57)	68	89
Total Other Comprehensive Income (Loss)	3,993	(3,366)
Comprehensive Income	30,439	10,599
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,452)	(3,287)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)
Comprehensive Income Attributable to PNMR	26,855	7,180
Public Service Company of New Mexico
Net Earnings	20,110	7,561
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	4,736	3,328
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(1,685)	(6,836)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience losses recognized as net periodic benefit cost, net of income tax expense (benefit)	987	839
Fair Value Adjustment for Cash Flow Hedges:
Total Other Comprehensive Income (Loss)	4,038	(2,669)
Comprehensive Income	24,148	4,892
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,452)	(3,287)
Comprehensive Income Attributable to PNMR	$ 20,696	$ 1,605

XML

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit	$ (3,030)	$ (2,130)
Reclassification adjustment for (gains) included in net earnings, income tax expense	1,078	4,374
Pension liability adjustment, income tax expense (benefit)	(631)	(537)
Change in fair market value, income tax (expense) benefit	72	503
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	(44)	(57)
Public Service Company of New Mexico
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit	(3,030)	(2,130)
Reclassification adjustment for (gains) included in net earnings, income tax expense	1,078	4,374
Pension liability adjustment, income tax expense (benefit)	$ (631)	$ (537)

XML

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash Flows From Operating Activities:
Net Earnings	$ 26,446	$ 13,965
Net earnings	22,862	10,546
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	65,888	58,563
Deferred income tax expense	10,787	7,187
Net unrealized (gains) on commodity derivatives	(1,345)	(1,435)
Realized (gains) on available-for-sale securities	(6,661)	(6,218)
Stock based compensation expense	2,687	2,653
Regulatory disallowances and restructuring costs	0	774
Other, net	(928)	(612)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	20,553	36,215
Materials, supplies, and fuel stock	1,836	(1,716)
Other current assets	11,441	(18,720)
Other assets	2,753	277
Accounts payable	(3,852)	2,004
Accrued interest and taxes	12,542	18,276
Other current liabilities	(10,009)	(16,583)
Other liabilities	(534)	(4,032)
Net cash flows from operating activities	131,604	90,598
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(114,830)	(278,764)
Proceeds from sales of available-for-sale securities	266,388	124,900
Purchases of available-for-sale securities	(267,891)	(126,101)
Return of principal on PVNGS lessor notes	0	8,547
Investment in Westmoreland Loan	0	(122,250)
Principal repayments on Westmoreland Loan	9,590	0
Other, net	128	150
Net cash flows from investing activities	(106,615)	(393,518)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	16,000	107,400
Long-term borrowings	0	182,500
Repayment of long-term debt	(9,444)	0
Proceeds from stock option exercise	1,112	3,275
Awards of common stock	(11,032)	(10,020)
Dividends paid	(19,448)	(17,656)
Valencia’s transactions with its owner	(4,028)	(3,999)
Other, net	(388)	(761)
Net cash flows from financing activities	(27,228)	260,739
Change in Cash and Cash Equivalents	(2,239)	(42,181)
Cash and Cash Equivalents at Beginning of Period	4,522	46,051
Cash and Cash Equivalents at End of Period	2,283	3,870
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	14,951	11,403
Income taxes paid (refunded), net	(125)	0
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	10,367	20,149
Public Service Company of New Mexico
Cash Flows From Operating Activities:
Net Earnings	20,110	7,561
Net earnings	16,658	4,274
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	44,691	40,225
Deferred income tax expense	7,878	3,727
Net unrealized (gains) on commodity derivatives	(1,345)	(1,435)
Realized (gains) on available-for-sale securities	(6,661)	(6,218)
Regulatory disallowances and restructuring costs	0	774
Other, net	(759)	(611)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	17,414	33,417
Materials, supplies, and fuel stock	2,083	(5,060)
Other current assets	12,399	(13,527)
Other assets	4,399	3,311
Accounts payable	(2,509)	5,130
Accrued interest and taxes	16,954	20,221
Other current liabilities	2,946	(9,335)
Other liabilities	(1,325)	(4,505)
Net cash flows from operating activities	116,275	73,675
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(65,781)	(238,734)
Proceeds from sales of available-for-sale securities	266,388	124,900
Purchases of available-for-sale securities	(267,891)	(126,101)
Return of principal on PVNGS lessor notes	0	8,547
Other, net	128	150
Net cash flows from investing activities	(67,156)	(231,238)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	(44,800)	118,800
Dividends paid	(132)	(132)
Valencia’s transactions with its owner	(4,028)	(3,999)
Other, net	(389)	(53)
Net cash flows from financing activities	(49,349)	114,616
Change in Cash and Cash Equivalents	(230)	(42,947)
Cash and Cash Equivalents at Beginning of Period	324	43,138
Cash and Cash Equivalents at End of Period	94	191
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	9,330	8,561
Income taxes paid (refunded), net	0	0
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	3,449	16,747
Texas-New Mexico Power Company
Cash Flows From Operating Activities:
Net earnings	7,604	7,456
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	15,921	14,936
Deferred income tax expense	2,746	194
Allowance for equity funds used during construction and other, net	(168)	0
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	3,138	2,798
Materials, supplies, and fuel stock	(247)	3,344
Other current assets	(838)	(1,842)
Other assets	(2,042)	(2,694)
Accounts payable	(788)	(3,788)
Accrued interest and taxes	(3,991)	939
Other current liabilities	134	163
Other liabilities	361	81
Net cash flows from operating activities	21,830	21,587
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(36,345)	(32,947)
Net cash flows from investing activities	(36,345)	(32,947)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	22,000	(44,000)
Short-term borrowings (repayments) - affiliate, net	1,700	(3,900)
Long-term borrowings	0	60,000
Dividends paid	(9,855)	0
Other, net	0	(740)
Net cash flows from financing activities	13,845	11,360
Change in Cash and Cash Equivalents	(670)	0
Cash and Cash Equivalents at Beginning of Period	671	1
Cash and Cash Equivalents at End of Period	1	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	2,584	1,719
Income taxes paid (refunded), net	0	0
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$ 2,235	$ 2,047

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Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 2,283	$ 4,522
Accounts receivable, net of allowance for uncollectible accounts	82,234	87,012
Unbilled revenues	41,808	58,284
Other receivables	27,098	28,245
Current portion of Westmoreland Loan	29,664	38,360
Materials, supplies, and fuel stock	66,140	73,027
Regulatory assets	910	3,855
Commodity derivative instruments	4,586	5,224
Income taxes receivable	5,953	6,066
Other current assets	66,093	73,444
Total current assets	326,769	378,039
Other Property and Investments:
Long-term portion of Westmoreland Loan	55,746	56,640
Available-for-sale securities	286,099	272,977
Other investments	419	547
Non-utility property	3,404	3,404
Total other property and investments	345,668	333,568
Utility Plant:
Plant in service, held for future use, and to be abandoned	7,009,698	6,944,534
Less accumulated depreciation and amortization	2,373,542	2,334,938
Net plant in service and plant held for future use	4,636,156	4,609,596
Construction work in progress	232,056	208,206
Nuclear fuel, net of accumulated amortization	87,379	86,913
Net utility plant	4,955,591	4,904,715
Deferred Charges and Other Assets:
Regulatory assets	496,012	501,223
Goodwill	278,297	278,297
Other deferred charges	75,342	75,238
Total deferred charges and other assets	849,651	854,758
Total assets	6,477,679	6,471,080
Current Liabilities:
Short-term debt	303,100	287,100
Current installments of long-term debt	414,856	273,348
Accounts payable	67,439	86,705
Customer deposits	11,207	11,374
Accrued interest and taxes	74,299	61,871
Regulatory liabilities	8,140	3,609
Commodity derivative instruments	360	2,339
Dividends declared	19,448	19,448
Other current liabilities	63,287	59,314
Total current liabilities	962,136	805,108
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,969,304	2,119,364
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	948,177	940,650
Regulatory liabilities	453,580	455,649
Asset retirement obligations	129,730	127,519
Accrued pension liability and postretirement benefit cost	121,632	125,844
Other deferred credits	126,607	140,545
Total deferred credits and other liabilities	1,779,726	1,790,207
Total liabilities	4,711,166	4,714,679
Commitments and Contingencies (See Note 11)
Cumulative preferred stock of subsidiary without mandatory redemption requirements	11,529	11,529
Company common stockholders’ equity:
Common stock	1,156,428	1,163,661
Accumulated other comprehensive income (loss), net of income taxes	(88,458)	(92,451)
Retained earnings	618,670	604,742
Total stockholders' equity	1,686,640	1,675,952
Non-controlling interest in Valencia	68,344	68,920
Total equity	1,754,984	1,744,872
Total liabilities and stockholders' equity	6,477,679	6,471,080
Public Service Company of New Mexico
Current Assets:
Cash and cash equivalents	94	324
Accounts receivable, net of allowance for uncollectible accounts	61,279	65,003
Unbilled revenues	33,897	48,289
Other receivables	23,486	25,514
Affiliate receivables	9,247	8,886
Materials, supplies, and fuel stock	62,318	64,401
Regulatory assets	0	3,442
Commodity derivative instruments	4,586	5,224
Income taxes receivable	25,977	25,807
Other current assets	60,425	67,355
Total current assets	281,309	314,245
Other Property and Investments:
Available-for-sale securities	286,099	272,977
Other investments	188	316
Non-utility property	96	96
Total other property and investments	286,383	273,389
Utility Plant:
Plant in service, held for future use, and to be abandoned	5,383,068	5,359,211
Less accumulated depreciation and amortization	1,832,695	1,809,528
Net plant in service and plant held for future use	3,550,373	3,549,683
Construction work in progress	184,129	158,122
Nuclear fuel, net of accumulated amortization	87,379	86,913
Net utility plant	3,821,881	3,794,718
Deferred Charges and Other Assets:
Regulatory assets	360,363	365,413
Goodwill	51,632	51,632
Other deferred charges	68,633	68,149
Total deferred charges and other assets	480,628	485,194
Total assets	4,870,201	4,867,546
Current Liabilities:
Short-term debt	16,200	61,000
Current installments of long-term debt	231,936	231,880
Accounts payable	49,613	55,566
Affiliate payables	33,967	23,183
Customer deposits	11,207	11,374
Accrued interest and taxes	51,942	34,819
Regulatory liabilities	8,140	3,517
Commodity derivative instruments	360	2,339
Dividends declared	132	132
Other current liabilities	47,659	33,551
Total current liabilities	451,156	457,361
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,400,036	1,399,489
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	755,872	748,666
Regulatory liabilities	421,177	423,701
Asset retirement obligations	128,794	126,601
Accrued pension liability and postretirement benefit cost	111,196	114,427
Other deferred credits	103,661	118,980
Total deferred credits and other liabilities	1,520,700	1,532,375
Total liabilities	3,371,892	3,389,225
Commitments and Contingencies (See Note 11)
Cumulative preferred stock of subsidiary without mandatory redemption requirements	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	(88,390)	(92,428)
Retained earnings	241,908	225,382
Total stockholders' equity	1,418,436	1,397,872
Non-controlling interest in Valencia	68,344	68,920
Total equity	1,486,780	1,466,792
Total liabilities and stockholders' equity	4,870,201	4,867,546
Texas-New Mexico Power Company
Current Assets:
Cash and cash equivalents	1	671
Accounts receivable, net of allowance for uncollectible accounts	20,955	22,009
Unbilled revenues	7,911	9,995
Other receivables	2,831	2,090
Materials, supplies, and fuel stock	3,822	8,626
Regulatory assets	910	413
Other current assets	630	1,031
Total current assets	37,060	44,835
Other Property and Investments:
Other investments	231	231
Non-utility property	2,240	2,240
Total other property and investments	2,471	2,471
Utility Plant:
Plant in service, held for future use, and to be abandoned	1,389,854	1,380,584
Less accumulated depreciation and amortization	439,781	429,397
Net plant in service and plant held for future use	950,073	951,187
Construction work in progress	38,832	16,978
Net utility plant	988,905	968,165
Deferred Charges and Other Assets:
Regulatory assets	135,649	135,810
Goodwill	226,665	226,665
Other deferred charges	5,305	5,277
Total deferred charges and other assets	367,619	367,752
Total assets	1,396,055	1,383,223
Current Liabilities:
Short-term debt	22,000	0
Short-term debt – affiliate	6,300	4,600
Accounts payable	8,634	16,709
Affiliate payables	2,854	3,793
Accrued interest and taxes	41,590	45,581
Regulatory liabilities	0	92
Other current liabilities	3,300	2,134
Total current liabilities	84,678	72,909
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	420,950	420,875
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	248,585	245,785
Regulatory liabilities	32,403	31,948
Asset retirement obligations	769	754
Accrued pension liability and postretirement benefit cost	10,436	11,417
Other deferred credits	7,250	6,300
Total deferred credits and other liabilities	299,443	296,204
Total liabilities	805,071	789,988
Commitments and Contingencies (See Note 11)
Company common stockholders’ equity:
Common stock	64	64
Paid-in-capital	454,166	454,166
Retained earnings	136,754	139,005
Total stockholders' equity	590,984	593,235
Total liabilities and stockholders' equity	$ 1,396,055	$ 1,383,223

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Allowance for uncollectible accounts	$ 1,212	$ 1,209
Accumulated depreciation, nuclear fuel	$ 50,378	$ 43,905
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
Public Service Company of New Mexico
Allowance for uncollectible accounts	$ 1,212	$ 1,209
Accumulated depreciation, nuclear fuel	$ 50,378	$ 43,905
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	Public Service Company of New Mexico	Public Service Company of New Mexico Total PNMR Common Stockholders’ Equity	Public Service Company of New Mexico Common Stock	Public Service Company of New Mexico AOCI	Public Service Company of New Mexico Retained Earnings	Public Service Company of New Mexico 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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative effect adjustment (Note 8)	$ 10,382	$ 10,382	$ 0	$ 0	$ 10,382	$ 0
Balance, as adjusted	1,755,254	1,686,334	1,163,661	(92,451)	615,124	68,920
Beginning balance at Dec. 31, 2016	1,744,872	1,675,952	1,163,661	(92,451)	604,742	68,920	$ 1,466,792	$ 1,397,872	$ 1,264,918	$ (92,428)	$ 225,382	$ 68,920
Beginning balance TNMP at Dec. 31, 2016	1,675,952						1,397,872						$ 593,235	$ 64	$ 454,166	$ 139,005
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Earnings	26,446	22,994			22,994	3,452	20,110	16,658		0	16,658	3,452
Net earnings	22,862						16,658						7,604			7,604
Total other comprehensive income	3,993	3,993		3,993			4,038	4,038		4,038	0
Subsidiary preferred stock dividends	(132)	(132)			(132)
Dividends declared on preferred stock							(132)	(132)		0	(132)
Dividends declared on common stock	(19,316)	(19,316)			(19,316)								(9,855)			(9,855)
Proceeds from stock option exercise	1,112	1,112	1,112
Awards of common stock	(11,032)	(11,032)	(11,032)
Stock based compensation expense	2,687	2,687	2,687
Valencia’s transactions with its owner	(4,028)					(4,028)	(4,028)					(4,028)
Ending balance at Mar. 31, 2017	1,754,984	$ 1,686,640	$ 1,156,428	$ (88,458)	$ 618,670	$ 68,344	1,486,780	$ 1,418,436	$ 1,264,918	$ (88,390)	$ 241,908	$ 68,344
Ending balance TNMP at Mar. 31, 2017	$ 1,686,640						$ 1,418,436						$ 590,984	$ 64	$ 454,166	$ 136,754

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Significant Accounting Policies and Responsibility for Financial Statements

3 Months Ended

Mar. 31, 2017

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, 2017 and December 31, 2016 and the consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2017 and 2016. 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 2016 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2017 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual 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 2016 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 5) and, through January 15, 2016, the PVNGS Capital Trust. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated. See Note 14.

New Accounting Pronouncements

Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below.

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

In May 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. When it becomes effective, the new standard will replace most existing revenue recognition guidance in GAAP. Since the issuance of ASU No. 2014-09, the FASB issued a one-year deferral in the effective date and has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. The new standard can be applied retrospectively to each prior period presented or on a modified retrospective basis with a cumulative effect adjustment to retained earnings on the date of adoption. The Company has not made a final decision on the transition method, but currently anticipates using the modified retrospective method. The Company will adopt the standard on January 1, 2018, its required effective date.

The Company has completed its initial assessment and made significant progress toward completing the evaluation of its revenues for potential changes to the amounts and timing of revenue recognition under the new guidance. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification. These industry specific issues include the impacts of the new guidance on its accounting for CIAC, collectability, and the presentation of revenues associated with “alternative revenue programs,” which primarily result from its approved rate rider programs. The Company is working towards completing its evaluation and drafting its revenue recognition disclosures under the new standard. The Company has not finalized conclusions and has not yet completely determined the effect of the standard on its financial reporting, but does not anticipate significant changes in revenue recognition associated with retail electric service rates or expect difficulty in completing this project by the required January 1, 2018 implementation date.

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

In January 2016, the FASB issued ASU No. 2016-01, which makes targeted improvements to GAAP regarding financial instruments. The new standard eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and will require those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. Also, the new standard will revise certain presentation and disclosure requirements. Under the new standard, accounting for investments in debt securities remains essentially unchanged. PNM currently classifies the investments held in the NDT and coal mine reclamation trusts as available for sale securities. Unrealized losses on these securities are recorded immediately through earnings and unrealized gains are recorded in AOCI until the securities are sold. The Company will adopt the new standard on January 1, 2018, its required effective date. At that time any unrealized gains, net of income taxes, recorded in AOCI related to equity securities will be reclassified to retained earnings as a cumulative effect adjustment and, thereafter, changes in the value of equity securities will be recorded in the Consolidated Statements of Earnings. The amount of the cumulative adjustment upon adoption will depend on the amounts recorded in AOCI at that time, but PNM had unrealized gains on equity securities, net of income taxes, recorded in AOCI of $6.8 million at March 31, 2017.

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

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

As discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, the Company has operating leases of office buildings, vehicles, equipment, and certain rights-of-way. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification. The Company has formed a project team, conducted outreach activities across its lines of business, and made significant progress in identifying arrangements, in addition to its existing operating lease arrangements, that may be classified as leases under the ASU. It is likely the arrangements currently classified as leases will continue to be recognized as leases under the new ASU. It is possible that other contractual arrangements not previously meeting the lease definition may contain elements that qualify as leases under ASU 2016-02 and that previously identified operating leases may be classified as financing leases under the new standard. The Company is in the process of analyzing each of the identified contractual arrangement to determine if it contains lease elements under the new standard and to quantify the potential impacts of identified lease arrangements. The Company anticipates this process will continue through the remainder of 2017 and possibly into 2018. Upon completion of that process, the Company will provide additional information about the expected financial impact of this ASU.

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

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

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

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

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

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

Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350)

In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. 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 this ASU 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 must adopt this ASU in 2020, but early adoption is permitted. The Company currently anticipates adopting this ASU in 2020. However, if there is an indication of potential impairment of goodwill as a result of an annual impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this ASU.

Accounting Standards Update 2017-07 – Compensation – Retirement Benefits (Topic 715)

In March 2017, the FASB issued ASU 2017-07 to improve the presentation of net periodic pension and other postretirement benefit costs. Currently, the Company presents all of its net periodic benefit costs as administrative and general expenses on its Condensed Consolidated Statements of Earnings, net of amounts capitalized to construction and other accounts. The amendments in this ASU require the service cost component of net benefit costs be presented in the same line item or items as compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of operating income with disclosures identifying where the other components of net benefit cost have been presented. The ASU also limits capitalization to only the service cost component of benefit costs. PNMR and its subsidiaries maintain qualified defined benefit pension and OPEB plans. Currently, net periodic benefit cost for the Company’s defined benefit pension plans do not include a service cost component and there is only a minor amount of service cost for the OPEB plans. Additional information about the Company’s plans is discussed in Note 12 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 10. The ASU requires retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit cost. The Company must adopt this ASU beginning January 1, 2018. The Company is in the process of analyzing the impacts of this new standard, including the treatment of benefit costs by the NMPRC, PUCT, and FERC in the regulatory process.

Accounting Standards Update 2017-08 - Receivables - Nonrefundable Fees and Other Costs (Topic 310-20) Premium Amortization on Purchased Callable Debt Securities

In March 2017, the FASB issued ASU No. 2017-08. The ASU amends the amortization period for certain purchased callable debt securities held at a premium. Under current GAAP, some entities amortize the premium as an adjustment of yield over the contractual life of the security. The update requires premiums to be amortized over the period to the earliest call date. The new standard is effective for the Company beginning on January 1, 2019. Early adoption is permitted including adoption in an interim period. The Company is in the process of analyzing the impacts of this new standard.

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Earnings Per Share

3 Months Ended

Mar. 31, 2017

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,
	2017		2016
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	22,862	$	10,546
Average Number of Common Shares:
Outstanding during period	79,654		79,654
Vested awards of restricted stock	112		104
Average Shares – Basic	79,766		79,758
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	346		406
Average Shares – Diluted	80,112		80,164
Net Earnings Per Share of Common Stock:
Basic	$	0.29	$	0.13
Diluted	$	0.29	$	0.13

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Segment Information

3 Months Ended

Mar. 31, 2017

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.

Corporate and Other

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

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

PNMR SEGMENT INFORMATION

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended March 31, 2017
Electric operating revenues	$	251,558		$	78,620		$	—		$	330,178
Cost of energy	81,317			21,487			—			102,804
Utility margin	170,241			57,133			—			227,374
Other operating expenses	95,894			23,797			(4,660		)	115,031
Depreciation and amortization	36,016			15,371			4,996			56,383
Operating income (loss)	38,331			17,965			(336		)	55,960
Interest income	2,816			—			2,065			4,881
Other income (deductions)	7,683			732			(335		)	8,080
Interest charges	(21,012		)	(7,404		)	(3,284		)	(31,700		)
Segment earnings (loss) before income taxes	27,818			11,293			(1,890		)	37,221
Income taxes (benefit)	7,708			3,689			(622		)	10,775
Segment earnings (loss)	20,110			7,604			(1,268		)	26,446
Valencia non-controlling interest	(3,452		)	—			—			(3,452		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	16,526		$	7,604		$	(1,268	)	$	22,862
At March 31, 2017:
Total Assets	$	4,870,201		$	1,396,055		$	211,423		$	6,477,679
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended March 31, 2016
Electric operating revenues	$	235,606		$	75,355		$	—		$	310,961
Cost of energy	72,444			19,925			—			92,369
Utility margin	163,162			55,430			—			218,592
Other operating expenses	108,001			22,368			(3,114		)	127,255
Depreciation and amortization	31,864			14,508			3,457			49,829
Operating income (loss)	23,297			18,554			(343		)	41,508
Interest income	1,522			—			2,100			3,622
Other income (deductions)	7,943			608			(1,068		)	7,483
Interest charges	(21,591		)	(7,369		)	(2,531		)	(31,491		)
Segment earnings (loss) before income taxes	11,171			11,793			(1,842		)	21,122
Income taxes (benefit)	3,610			4,337			(790		)	7,157
Segment earnings (loss)	7,561			7,456			(1,052		)	13,965
Valencia non-controlling interest	(3,287		)	—			—			(3,287		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	4,142		$	7,456		$	(1,052	)	$	10,546
At March 31, 2016:
Total Assets	$	4,719,346		$	1,312,402		$	242,064		$	6,273,812
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2017

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, 2017 and 2016 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, 2016	$	4,320		$	(96,748	)	$	(92,428	)	$	(23	)	$	(92,451	)
Amounts reclassified from AOCI (pre-tax)	(2,763		)	1,618			(1,145		)	112			(1,033		)
Income tax impact of amounts reclassified	1,078			(631		)	447			(44		)	403
Other OCI changes (pre-tax)	7,766			—			7,766			(185		)	7,581
Income tax impact of other OCI changes	(3,030		)	—			(3,030		)	72			(2,958		)
Net after-tax change	3,051			987			4,038			(45		)	3,993
Balance at March 31, 2017	$	7,371		$	(95,761	)	$	(88,390	)	$	(68	)	$	(88,458	)

Balance at December 31, 2015	$	17,346		$	(88,822	)	$	(71,476	)	$	44		$	(71,432	)
Amounts reclassified from AOCI (pre-tax)	(11,210		)	1,376			(9,834		)	146			(9,688		)
Income tax impact of amounts reclassified	4,374			(537		)	3,837			(57		)	3,780
Other OCI changes (pre-tax)	5,458			—			5,458			(1,289		)	4,169
Income tax impact of other OCI changes	(2,130		)	—			(2,130		)	503			(1,627		)
Net after-tax change	(3,508		)	839			(2,669		)	(697		)	(3,366		)
Balance at March 31, 2016	$	13,838		$	(87,983	)	$	(74,145	)	$	(653	)	$	(74,798	)

Pre-tax amounts reclassified from AOCI related to “Unrealized Gains on Available-for-Sale Securities” are included in “Gains on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “Pension Liability Adjustment” are reclassified to “Operating Expenses – Administrative and general” in the Condensed Consolidated Statements of Earnings. For the three months ended March 31, 2017 and 2016, 19.8% and 22.7% of the pension amounts reclassified were capitalized into construction work in process and 5.4% and 2.6% were capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC and capitalized interest. 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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Variable Interest Entities

3 Months Ended

Mar. 31, 2017

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 9 of the Notes to Consolidated Financial Statements in the 2016 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, 2017 and 2016, PNM paid $4.9 million and $4.8 million for fixed charges and $0.1 million and $0.2 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. 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 (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market value.

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,
	2017			2016
	(In thousands)
Operating revenues	$	4,927		$	4,937
Operating expenses	(1,475		)	(1,650		)
Earnings attributable to non-controlling interest	$	3,452		$	3,287

Financial Position

	March 31,		December 31,
	2017		2016
	(In thousands)
Current assets	$	2,841	$	2,551
Net property, plant, and equipment	66,237		66,947
Total assets	69,078		69,498
Current liabilities	734		578
Owners’ equity – non-controlling interest	$	68,344	$	68,920

Westmoreland San Juan LLC (“WSJ”) and SJCC

As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS from SJCC under a coal supply agreement (“CSA”). That section includes information on the purchase of SJCC by WSJ on January 31, 2016, as well as a $125.0 million loan (the “Westmoreland Loan”) from NM Capital, a subsidiary of PNMR, to WSJ, which loan provided substantially all of the funds required for the SJCC purchase, and the issuance of $30.3 million in letters of credit to facilitate the issuance of reclamation bonds required in order for SJCC to mine coal to be supplied to SJGS. The Westmoreland Loan and the letters of credit support result in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital could be subject to loss in the event of a default by WSJ under the Westmoreland Loan and/or performance under the letter of credit support was required.  Principal payments under the Westmoreland Loan began on August 1, 2016 and are required quarterly thereafter. Interest is also paid quarterly beginning on May 3, 2016.

At March 31, 2017, the amount outstanding under the Westmoreland Loan was $85.4 million. In addition, interest receivable of $1.4 million is included in Other receivables. The Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. A principal payment of $9.6 million plus interest of $2.2 million is due on May 2, 2017. As of April 24, 2017, $11.8 million was held in a SJCC bank account that is restricted solely to be used to service the Westmoreland Loan. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations.  In such event, NM Capital would likely engage a third-party mining company to operate SJCC so that operations of the mine are not disrupted. The acquisition of SJCC by WSJ for approximately $125.0 million is a recently negotiated, arms-length transaction between Westmoreland and BHP, which amount should approximate the fair value of SJCC at the date of acquisition.  If WSJ were to default, NM Capital should be able to acquire assets of approximately the value of the Westmoreland Loan without a significant loss. Furthermore, PNMR considers the possibility of loss under the letters of credit support to be remote since the purpose of posting the bonds is to provide assurance that SJCC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the CSA. Also, much of the mine reclamation activities will not be performed for many years in the future, including after the expiration of the CSA and the final maturity of the Westmoreland Loan. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations.

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

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Lease Commitments

3 Months Ended

Mar. 31, 2017

Leases [Abstract]

Lease Commitments

Lease Commitments

The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS. All of the Company’s leases are currently accounted for as operating leases. See Note 1. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, including PNM’s actions with regard to renewal and purchase options under the PVNGS leases.

The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. The four Unit 1 leases have been extended to expire on January 15, 2023 and one of the Unit 2 leases has been extended to expire on January 15, 2024. For the other three PVNGS Unit 2 leases, PNM exercised its fair market value options to purchase the assets underlying those leases on the expiration date of the original leases. On January 15, 2016, PNM paid $78.1 million to the lessor under one lease for 31.3 MW of the entitlement from PVNGS Unit 2 and $85.2 million to the lessors under the other two leases for 32.8 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.

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, 2017, amounts due to the lessors under the circumstances described above would be up to $173.0 million, payable on July 15, 2017 in addition to the scheduled lease payments due on July 15, 2017.

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Fair Value of Derivative and Other Financial Instruments

3 Months Ended

Mar. 31, 2017

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 the Company’s energy related derivative contracts and other financial instruments is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2016 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 retail and wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its wholesale customers not covered under a FPPAC. However, as discussed below, PNM has hedging arrangements for the output of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers. Beginning January 1, 2018, PNM expects to be exposed to market risk for the 65 MW of SJGS Unit 4 that is anticipated to be transferred to PNM from PNMR Development (Note 11). PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases.

Commodity Risk

Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.

Accounting for Derivatives

Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. During the three months ended March 31, 2017 and the year ended December 31, 2016, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. The Company has no trading transactions.

Commodity Derivatives

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

	Economic Hedges
	March 31, 2017			December 31, 2016
PNMR and PNM	(In thousands)
Current assets	$	4,586		$	5,224
Current liabilities	(360		)	(2,339		)
Net	$	4,226		$	2,885

Included in the above table are $2.0 million and $2.7 million of current assets at March 31, 2017 and December 31, 2016 related to contracts for the sale of energy from PVNGS Unit 3 through 2017 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at March 31, 2017 and December 31, 2016.

At March 31, 2017 and December 31, 2016, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at March 31, 2017 and December 31, 2016, amounts posted as cash collateral under margin arrangements were $1.5 million and $2.6 million for both PNMR and PNM. At March 31, 2017 and December 31, 2016, obligations to return cash collateral were $0.1 million and $0.1 million for both PNMR and PNM. Cash collateral amounts are included in other current assets and other current liabilities on the 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. The table above includes $0.1 million of current assets and less than $0.1 million of current liabilities at March 31, 2017 and $0.2 million of current assets and $0.1 million of current liabilities at December 31, 2016 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.

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

	Economic Hedges
	Three Months Ended
	March 31,
	2017		2016
PNMR and PNM	(In thousands)
Electric operating revenues	$	3,341	$	2,684
Cost of energy	11		(145		)
Total gain (loss)	$	3,352	$	2,539

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

	Economic Hedges
	MMBTU	MWh
PNMR and PNM
March 31, 2017	100,000	(1,834,125	)
December 31, 2016	254,100	(2,471,600	)

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

The Company 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. Contractual liability represents those commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. Cash collateral that has been posted under the existing contracts does not reflect letters of credit under the Company’s revolving credit facilities that may have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions. At March 31, 2017 and December 31, 2016, the Company had no contractual liability, posted cash collateral, or net exposure related to these contingent requirements for contracts in net liability positions.

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently included in retail rates, that unit’s power is being sold in the wholesale market. PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers beginning on January 1, 2018. As of March 31, 2017, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2017, at market price plus a premium.  Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates for substantially all of the sales through 2017, which average approximately $29 per MWh.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and trusts for PNM’s share of final reclamation costs related to the coal mines serving SJGS and Four Corners (Note 11). At March 31, 2017 and December 31, 2016, the fair value of available-for-sale securities included $266.1 million and $253.9 million for the NDT and $20.0 million and $19.1 million for the mine reclamation trusts. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	March 31, 2017				December 31, 2016
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	8,047	$	—	$	23,683
Equity securities:
Domestic value	3,044		70,043		1,135		34,796
Domestic growth	4,438		65,127		3,032		47,595
International and other	3,555		36,442		2,029		27,481
Fixed income securities:
U.S. Government	178		31,410		115		40,962
Municipals	617		33,218		585		43,789
Corporate and other	574		41,812		553		54,671
	$	12,406	$	286,099	$	7,449	$	272,977

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the decrease in realized impairment losses of$1.1 millionand $1.6 million for the three months ended March 31, 2017 and 2016.

	Three Months Ended
	March 31,
	2017			2016
PNMR and PNM	(In thousands)
Proceeds from sales	$	266,388		$	124,900
Gross realized gains	$	8,645		$	10,716
Gross realized (losses)	$	(3,085	)	$	(6,116	)

Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. At March 31, 2017 and December 31, 2016, held-to-maturity securities consist of the Westmoreland Loan.

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

At March 31, 2017, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR
	(In thousands)
Within 1 year	$	3,852	$	—
After 1 year through 5 years	23,629		96,444
After 5 years through 10 years	29,024		—
After 10 years through 15 years	3,963		—
After 15 years through 20 years	8,728		—
After 20 years	37,244		—
	$	106,440	$	96,444

Fair Value Disclosures

The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models. The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the three months ended March 31, 2017 and the year ended December 31, 2016.

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

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at March 31, 2017 and December 31, 2016 for items recorded at fair value.

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
PNMR and PNM	(In thousands)
March 31, 2017
Available-for-sale securities
Cash and cash equivalents	$	8,047		$	8,047	$	—
Equity securities:
Domestic value	70,043			70,043		—
Domestic growth	65,127			65,127		—
International and other	36,442			33,212		3,230
Fixed income securities:
U.S. Government	31,410			30,179		1,231
Municipals	33,218			—		33,218
Corporate and other	41,812			—		41,812
	$	286,099		$	206,608	$	79,491
Commodity derivative assets	$	4,586		$	—	$	4,586
Commodity derivative liabilities	(360		)	—		(360		)
Net	$	4,226		$	—	$	4,226
December 31, 2016
Available-for-sale securities
Cash and cash equivalents	$	23,683		$	23,683	$	—
Equity securities:
Domestic value	34,796			34,796		—
Domestic growth	47,595			47,595		—
International and other	27,481			27,481		—
Fixed income securities:
U.S. Government	40,962			39,723		1,239
Municipals	43,789			—		43,789
Corporate and other	54,671			23,158		31,513
	$	272,977		$	196,436	$	76,541
Commodity derivative assets	$	5,224		$	—	$	5,224
Commodity derivative liabilities	(2,339		)	—		(2,339		)
Net	$	2,885		$	—	$	2,885

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

					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
March 31, 2017	(In thousands)
PNMR
Long-term debt	$	2,384,160	$	2,525,916	$	—	$	2,525,916	$	—
Westmoreland Loan	$	85,410	$	96,444	$	—	$	—	$	96,444
Other investments	$	419	$	1,051	$	419	$	—	$	632
PNM
Long-term debt	$	1,631,972	$	1,728,276	$	—	$	1,728,276	$	—
Other investments	$	188	$	188	$	188	$	—	$	—
TNMP
Long-term debt	$	420,950	$	464,877	$	—	$	464,877	$	—
Other investments	$	231	$	231	$	231	$	—	$	—
December 31, 2016
PNMR
Long-term debt	$	2,392,712	$	2,540,693	$	—	$	2,540,693	$	—
Westmoreland Loan	$	95,000	$	100,893	$	—	$	—	$	100,893
Other investments	$	547	$	1,164	$	547	$	—	$	617
PNM
Long-term debt	$	1,631,369	$	1,730,157	$	—	$	1,730,157	$	—
Other investments	$	316	$	316	$	316	$	—	$	—
TNMP
Long-term debt	$	420,875	$	468,329	$	—	$	468,329	$	—
Other investments	$	231	$	231	$	231	$	—	$	—

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Stock-Based Compensation

3 Months Ended

Mar. 31, 2017

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. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 13 of the Notes to Consolidated Financial Statements in the 2016 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, the awards vest ratably over three years from the grant date of the award. However, awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards. Beginning with 2017 awards, the vesting period for awards of restricted stock to non-employee members of the Board will be one year.

The stock-based compensation expense related to restricted stock awards without performance or market conditions to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for other such awards is amortized to compensation expense over the shorter of the requisite vesting period or the period until the participant becomes retirement eligible. Compensation expense for performance-based shares is recognized ratably over the performance period and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At March 31, 2017 and December 31, 2016, PNMR had unrecognized expense related to stock awards of $6.9 million and $4.5 million, which are expected to be recognized over an average of 2.4 and 1.8 years.

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

The FASB issued Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718) to simplify several aspects of the accounting for share-based payment transactions and eliminate diversity in practice. PNMR’s historical accounting for stock compensation complies with ASU 2016-09, except for the treatment of the income tax consequences of awards and the presentation of reductions to taxes payable on the Consolidated Statements of Cash Flows. Prior to ASU 2016-09, benefits resulting from income tax deductions in excess of compensation cost recognized under GAAP for vested restricted stock and on exercised stock options (“excess tax benefits”) were recorded to equity provided the excess tax benefits reduced income taxes payable. Deficiencies resulting from tax deductions related to stock awards that were below recognized compensation cost upon vesting and on canceled stock options were recorded to equity. PNMR has not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. ASU 2016-09 requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as cash flows from operating activities. PNMR adopted ASU 2016-09 as of January 1, 2017 and recorded excess tax benefits of $1.8 million in the three months ended March 31, 2017 of which $1.3 million was recorded at PNM and $0.5 million at TNMP. As required by ASU 2016-09, PNMR recorded the excess tax benefits that were not recognized in prior years, due to its net operating loss position, as a cumulative effect adjustment of $10.4 million, increasing retained earnings and decreasing accumulated deferred income taxes on the Condensed Consolidated Balance Sheets. When excess tax benefits are used to reduce income taxes payable, the benefit will be reflected in cash flows from operating activities.

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

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

	Three Months Ended March 31,
Restricted Shares and Performance Based Shares	2017			2016
Expected quarterly dividends per share	$	0.2425		$	0.2200
Risk-free interest rate	1.58		%	1.00		%
Market-Based Shares
Dividend yield	2.67		%	2.74		%
Expected volatility	20.80		%	20.44		%
Risk-free interest rate	1.54		%	0.97		%

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, 2017:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2016	218,316		$	27.59	305,874		$	12.29
Granted	231,107		$	22.12	—		$	—
Exercised	(248,003	)	$	20.26	(59,600	)	$	18.66
Forfeited	(822	)	$	27.86	—		$	—
Expired	—		$	—	(3,000	)	$	30.50
Outstanding at March 31, 2017	200,598		$	30.35	243,274		$	10.51

PNMR’s stock-based compensation program provides for performance and market targets through 2019. Included as granted and as exercised in the above table are 49,682 previously awarded shares that were earned for the 2014 through 2016 performance measurement period and ratified by the Board in February 2017 (based upon achieving market targets at “target” levels, weighted at 60%, and not meeting performance targets, weighted at 40%). Excluded from the above table are maximums of 163,712, 137,036, and 133,632 shares for the three-year performance periods ending in 2017, 2018, and 2019 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she was to receive 135,000 shares of PNMR’s common stock if PNMR met specific market targets at the end of 2016 and she remained an employee of the Company. Under the agreement, she received 35,000 of the total shares in 2015 since PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2016 and the Board ratified her receiving the remaining 100,000 shares, which is included in the above table, in February 2017. The retention award was made under the PEP and was approved by the Board on February 28, 2012.

Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieved the specific performance target for the period from January 1, 2015 through December 31, 2016, he was to receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. The specified market target was achieved at the end of 2016 and the Board ratified him receiving $100,000 of PNMR common stock in February 2017 based on a market per share value of $36.30 on the grant date of March 3, 2017, or 2,754 shares, which is included in the above table. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

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

At March 31, 2017, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.4 million with a weighted-average remaining contract life of 2.1 years. At March 31, 2017, no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date.

The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options:

	Three Months Ended March 31,
Restricted Stock	2017		2016
Weighted-average grant date fair value	$	22.12	$	26.05
Total fair value of restricted shares that vested (in thousands)	$	5,024	$	4,131
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)	$	945	$	853

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Financing

3 Months Ended

Mar. 31, 2017

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 revolving credit facilities and the Company’s term loans contains a single financial covenant, which requires the maintenance of a debt-to-capital ratio of less than or equal to 65%, and generally also include customary covenants, events of default, cross default provisions, and change of control provisions. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. Additional information concerning financing activities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K.

Financing Activities

On March 9, 2015, PNMR entered into a $150.0 million Term Loan Agreement (“PNMR 2015 Term Loan Agreement”) between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and administrative agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate and must be repaid on or before March 9, 2018. In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 1.927%, subject to change if there is a change in PNMR’s credit rating, for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018. This hedge is accounted for as a cash-flow hedge and had a fair value gain of $0.2 million at March 31, 2017, which is included in Other current assets on the Condensed Consolidated Balance Sheets, and a fair value loss of less than $0.1 million at December 31, 2016. 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.

The interest rate on the PNMR 2015 Term Loan Agreement was 1.75% at March 31, 2017. The $100.0 million PNMR 2016 Two-Year Term Loan and the $175.0 million PNM 2016 Term Loan Agreement also bear interest at variable rates, which were 1.93% and 1.59% at March 31, 2017.

As discussed in Note 11, NM Capital, a wholly owned subsidiary of PNMR, entered into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent, as of February 1, 2016. The BTMU Term Loan Agreement has a maturity date of February 1, 2021 and bears interest at a rate based on LIBOR plus a customary spread, which aggregated 3.79% at March 31, 2017. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. The BTMU Term Loan Agreement and the guaranty include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio of 65%, and customary events of default, a cross default provision, and a change of control provision consistent with PNMR’s other term loan agreements. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding of $125.0 million (the “Westmoreland Loan”) to a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price of the stock of SJCC. The BTMU Term Loan Agreement requires that NM Capital utilize all amounts, less taxes and fees, it receives under the Westmoreland Loan to repay the BTMU Term Loan Agreement. The principal balance outstanding under the BTMU Term Loan Agreement was $82.8 million at March 31, 2017. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $33.5 million on the BTMU Term Loan Agreement in the twelve months ended March 31, 2018.

On October 21, 2016, PNMR entered into letter of credit arrangements with JPMorgan Chase Bank, N.A. (the “JPM LOC Facility”) under which letters of credit aggregating $30.3 million were issued to facilitate the posting of reclamation bonds, which SJCC is required to post in connection with permits relating to the operation of the San Juan mine (Note 11).

On March 9, 2017, PNMR entered into a four-year hedging agreement whereby it effectively established a fixed interest rate of 1.926% plus a customary spread, subject to change if there is a change in PNMR’s credit rating, for $50.0 million of its variable rate short-term debt. This hedge is accounted for as a cash-flow hedge and had a fair value loss of $0.4 million at March 31, 2017, which is included in Other current liabilities on the Condensed Consolidated Balance Sheets. The fair value was 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.

Short-term Debt and Liquidity

Currently, the PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. In November 2016, PNMR and PNM entered into agreements to extend the maturity of both facilities from October 31, 2020 to October 31, 2021. However, one lender, whose current commitment is $10.0 million under the PNMR Revolving Credit Facility and $40.0 million under the PNM Revolving Credit Facility, did not agree to extend its commitments beyond October, 31, 2020. Unless one or more of the other current lenders or a new lender assumes the commitments of the non-extending lender, the financing capacities will be reduced to $290.0 million for the PNMR Revolving Credit Facility and $360.0 million for the PNM Revolving Credit Facility from November 1, 2020 through October 31, 2021. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. The TNMP Revolving Credit Facility matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At March 31, 2017, the weighted average interest rate was 2.19% for the PNMR Revolving Credit Facility, 2.11% for the PNM Revolving Credit Facility, 1.94% for the TNMP Revolving Credit Facility, and 1.83% for the PNMR 2016 One-Year Term Loan, which matures in December 2017. Short-term debt outstanding consisted of:

	March 31,		December 31,
Short-term Debt	2017		2016
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	16,200	$	35,000
PNM New Mexico Credit Facility	—		26,000
TNMP Revolving Credit Facility	22,000		—
PNMR:
PNMR Revolving Credit Facility	164,900		126,100
PNMR 2016 One-Year Term Loan	100,000		100,000
	$	303,100	$	287,100

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $6.2 million, $2.5 million, and $0.1 million at March 31, 2017 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of March 31, 2017, TNMP had intercompany borrowings from PNMR of $6.3 million.

At April 24, 2017, PNMR, PNM, and TNMP had $137.7 million, $389.7 million, and $34.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $43.0 million of availability under the PNM New Mexico Credit Facility. Total availability at April 24, 2017, on a consolidated basis, was $605.3 million for PNMR. As of April 24, 2017, TNMP had borrowings of $5.0 million from PNMR under its intercompany loan agreement. At April 24, 2017, PNMR, PNM, and TNMP had consolidated invested cash of $1.5 million, none, and none.

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Pension and Other Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2017

Compensation and Retirement Disclosure [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.

Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. See New Accounting Pronouncements in Note 1.

PNM Plans

The following tables present the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2017			2016			2017			2016			2017		2016
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	24		$	35		$	—	$	—
Interest cost	6,727			7,577			1,006			1,087			174		203
Expected return on plan assets	(8,451		)	(8,854		)	(1,308		)	(1,371		)	—		—
Amortization of net (gain) loss	4,001			3,455			921			286			78		64
Amortization of prior service cost	(241		)	(241		)	(416		)	(7		)	—		—
Net periodic benefit cost	$	2,036		$	1,937		$	227		$	30		$	252	$	267

PNM did not make any contributions to its pension plan trustin the three months ended March 31, 2017 and 2016 and does not anticipate making any contributions to the pension plan in 2017-2021, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.1% to 4.9%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made no contributions to the OPEB trust in the three months ended March 31, 2017 and$0.8 millionin the three months ended March 31, 2016. PNM does not expect to make any contributions to the OPEB trust in 2017-2021.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.5 million and$0.5 millionin the three months ended March 31, 2017 and 2016 and are expected to total $1.5 million during 2017 and $5.8 million for 2018-2021.

TNMP Plans

The following tables present the components of the TNMP Plans’ net periodic benefit cost (income):

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2017			2016			2017			2016			2017		2016
	(In thousands)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	—		$	—		$	36		$	46		$	—	$	—
Interest cost	722			826			139			169			8		10
Expected return on plan assets	(945		)	(986		)	(114		)	(122		)	—		—
Amortization of net (gain) loss	231			175			(20		)	(10		)	2		1
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost (Income)	$	8		$	15		$	41		$	83		$	10	$	11

TNMP did not make any contributions to its pension plan trust in the three months ended March 31, 2017 and 2016 and does not anticipate making any contributions in 2017-2021, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.1% to 4.9%. 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 $0.7 million to the OPEB trust in the three months ended March 31, 2017 and no contribution in the three months ended March 31, 2016. TNMP does not expect to make any additional contributions to the OPEB trust in 2017 and expects to make contributions totaling $1.4 million for 2018-2021. 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, 2017 and 2016 and are expected to total $0.1 million during 2017 and $0.4 million in 2018-2021.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 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. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, or other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient 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 2016 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 DOE entered into a settlement agreement, which establishes a process for the payment of claims for costs incurred through December 31, 2016. The settlement agreement has been extended to 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 fuel is consumed. At March 31, 2017 and December 31, 2016, PNM had a liability for interim storage costs of $12.0 million and $12.1 million included in other deferred credits.

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

On June 8, 2012, the DC Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (the “Waste Confidence Decision”). The DC Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’s actions. The DC Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient and, therefore, remanded the Waste Confidence Decision update for further action consistent with NEPA. On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision.

In September 2013, the NRC issued its draft generic EIS to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel.  The continued storage rule adopted the findings of the generic EIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. The NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the DC Circuit issued its June 2012 decision although PVNGS had not been involved in any licensing actions affected by that decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. On May 19, 2016, the NRC denied petitions filed by multiple petitioners to revise the August 2014 rule. The DC Circuit issued an order upholding the August 2014 rule on June 3, 2016 and denied a subsequent petition for rehearing on August 8, 2016.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged, in the DC Circuit, DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval, as ordered by the DC Circuit. On May 16, 2014, the DOE adjusted the fee to zero. PNM anticipates challenges to this action and is unable to predict its ultimate outcome.

The Clean Air Act

Regional Haze

In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.

SJGS

BART Compliance –SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K contains detailed information concerning the BART compliance process, including interactions with governmental agencies responsible for environmental oversight and the NMPRC approval process. In December 2015, PNM received NMPRC approval for the plan to comply with the EPA regional haze rule at SJGS. Under the approved plan, the installation of selective non-catalytic reduction technology (“SNCR”) was required on SJGS Units 1 and 4, which was completed in early 2016, and Units 2 and 3 are to be retired by the end of 2017. In addition to the required SNCR equipment, the NSR permit, which was required to be obtained in order to install the SNCRs, specified that SJGS Units 1 and 4 be converted to balanced draft technology (“BDT”). PNM’s share of the total costs for SNCRs and BDT equipment was $77.9 million. See Note 12 for information concerning the NMPRC’s treatment of BDT in PNM’s NM 2015 Rate Case. Although operating costs will be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 have increased with the installation of SNCR and BDT equipment.

On December 16, 2015, the NMPRC issued an order regarding SJGS. As provided in that order:

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

• PNM is granted a CCN to acquire an additional 132 MW in SJGS Unit 4, effective January 1, 2018, with an initial book value of zero, plus the costs of SNCR and other capital additions

• PNM is granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017, including transmission assets associated with PVNGS Unit 3, (currently estimated to aggregate approximately $156 million)

• No later than December 31, 2018, and before entering into a binding agreement for post-2022 coal supply for SJGS, PNM will file its position and supporting testimony in a NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022; all parties to the stipulation agree to support this case being decided within six months (to facilitate the 2018 filing PNM is developing two resource portfolios in its 2017 IRP, which is discussed in Note 12, to be filed in July 2017, one with SJGS continuing beyond mid-2022 and one where it is shut down)

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

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

• PNM will accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022 (cost recovery for PNM’s BDT project is discussed in Note 12)

• PNM will not recover approximately $20 million of other costs incurred in connection with CAA compliance

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

At December 31, 2015, PNM recorded losses for regulatory disallowances and restructuring costs, aggregating $165.7 million, reflecting a $127.6 million regulatory disallowance to reflect the write-off of the 50% of the estimated December 31, 2017 net book value that will not be recovered, the other unrecoverable costs, and the $16.5 million increase in the estimated liability recorded for coal mine reclamation resulting from the new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”). The ultimate amount of the regulatory disallowance will be dependent on the actual December 31, 2017 net undepreciated book values of SJGS Units 2 and 3. Accordingly, the amount initially recorded will be adjusted periodically to reflect changes in the projected December 31, 2017 net book values. Additional information about the CSA is discussed under Coal Supply below and in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K.

During 2016, PNM revised its estimates of the December 31, 2017 projected book value of SJGS Units 2 and 3 and the other unrecoverable costs, which resulted in a net expense of $3.7 million, including a $4.5 million expense related to a refinement of the estimated liability for coal mine reclamation from the new coal mine reclamation arrangement. PNM recorded $0.8 million of such revision during the three months ended March 31, 2016, which is reflected in regulatory disallowances and restructuring costs on the Condensed Consolidated Statement of Earnings. In addition, PNMR Development recorded an expense of $0.6 million in the three months ended March 31, 2016 for costs it was obligated to reimburse the other SJGS participants under the restructuring arrangement, which is included in other deductions on the Condensed Consolidated Statement of Earnings. At March 31, 2017, the carrying value for PNM’s current ownership share of SJGS Units 2 and 3 is comprised of plant in service of $471.8 million and accumulated depreciation and amortization (including cost of removal) of $206.4 million for a net undepreciated book value of $265.4 million, offset by 50% (which equals $128.6 million) of the anticipated December 31, 2017 undepreciated net book value of SJGS Units 2 and 3 that will not be recovered, resulting in the net carrying value for SJGS Units 2 and 3 being $136.8 million at March 31, 2017.

On January 14, 2016, NEE filed a Notice of Appeal with the NM Supreme Court of the NMPRC’s December 16, 2015 order. On July 22, 2016, NEE filed a brief alleging that the NMPRC’s decision violated New Mexico statutes and NMPRC regulations because PNM did not adequately consider replacement resources other than those proposed by PNM, the NMPRC did not require PNM to adequately address and mitigate ratepayer risk, the NMPRC unlawfully shifted the burden of proof, and the NMPRC’s decision was arbitrary and capricious.  Answer briefs refuting NEE’s claims were filed on November 2, 2016 by PNM, the NMPRC, and certain intervenors. Reply briefs were filed by NEE on January 9, 2017 and the parties presented oral argument to the court on January 25, 2017. The court has not rendered a decision on the appeal and there is no required time frame for a decision. In addition, on March 31, 2016, NEE filed a complaint with the NMPRC against PNM regarding the financing provided by NM Capital to facilitate the sale of SJCC. The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. The NMPRC has taken no action on this matter. PNM cannot currently predict the outcome of these matters.

SJGS Ownership Restructuring Matters – As discussed in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Report on Form 10-K, SJGS currently is jointly owned by PNM and eight other entities. In connection with the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants expressed a desire to exit their ownership in the plant. As a result, the SJGS participants negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items. The exiting participants currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4, but none of SJGS Units 1 and 2. PNM currently owns 50.0% of SJGS Units 1, 2, and 3 and 38.5% of SJGS Unit 4.

Following mediated negotiations, the SJGS participants executed the San Juan Project Restructuring Agreement (“RA”) on July 31, 2015. The RA provides the essential terms of restructured ownership and addresses other related matters, including that the exiting participants remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit. PNMR Development became a party to the RA and agreed to acquire a 65 MW ownership interest in SJGS Unit 4 on the exit date, which is anticipated to be December 31, 2017, but has obligations related to Unit 4 before then. On the exit date, PNM would acquire 132 MW and PNMR Development would acquire 65 MW of the capacity in SJGS Unit 4 from the exiting owners for no initial cost other than funding capital improvements, including the costs of installing SNCR and BDT equipment. PNMR Development’s share of the costs of installing SNCR and BDT equipment amounted to $7.6 million. PNMR currently anticipates that PNMR Development will transfer the rights and obligations related to the 65 MW to PNM prior to December 31, 2017 in order to facilitate dispatch of power from that capacity. As ordered by the NMPRC, PNM would treat the 65 MW as merchant utility plant that would be excluded from retail rates. Reflecting the additions of the 132 MW and 65 MW, PNM’s ownership share would be 77.3% in SJGS Unit 4 and an aggregate of 66.3% in SJGS Units 1 and 4.

The RA became effective contemporaneously with the effectiveness of the new CSA. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which as discussed in Coal Supply below, occurred at 11:59 PM on January 31, 2016. The RA sets forth the terms under which PNM acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and will supply coal to the exiting participants for the period from January 1, 2016 through December 31, 2017, which arrangement provides economic benefits that are being passed on to PNM’s customers through the FPPAC.

Other SJGS Matters – Although the RA results in an agreement among the SJGS participants enabling compliance with current CAA requirements, it is possible that the financial impact of climate change regulation or legislation, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant.

Four Corners

On August 6, 2012, EPA issued its Four Corners FIP with a final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to permanently close Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lbs/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.

PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $90.2 million, including amounts incurred through March 31, 2017 and PNM’s AFUDC. PNM is seeking recovery from its ratepayers of these costs in its NM 2016 Rate Case discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2016 Annual Report on Form 10-K and Note 12. PNM is unable to predict the ultimate outcome of this matter.

The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

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

Carbon Dioxide Emissions

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

The Clean Power Plan establishes state-by-state targets for carbon emissions reduction and establishes deadlines for states to submit initial plans to EPA by September 6, 2016, with a potential two-year extension, and final plans by 2018. The September deadline has passed with no action and the 2018 deadline could be adjusted due to the stay of the Clean Power Plan issued by the US Supreme Court and pending litigation described below. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide, but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. State measures plans may only be used with mass-based goals and must include “backstop” federally enforceable standards that will become effective if the state measures fail to achieve the expected level of emission reductions.

On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan. On January 26, 2016, 29 states and state agencies filed a petition to the US Supreme Court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court issued a 5-4 decision granting the stay pending judicial review of the rule by the DC Circuit.  The decision means the Clean Power Plan is not in effect and states are not obliged to comply with its requirements. The DC Circuit heard oral arguments on September 27, 2016 in the case challenging the Clean Power Plan, but has not rendered a decision.

The proposed federal plan released concurrently with the Clean Power Plan is important to Four Corners and the Navajo Nation.  Since the Navajo Nation does not have primacy over its air quality program, the EPA would be the regulatory authority responsible for implementing the Clean Power Plan on the Navajo Nation, if the Clean Power Plan is sustained under the current administration.  In addition, the proposed rule recommends that EPA determine it is “necessary or appropriate” for EPA to regulate CO₂ emissions on the Navajo Nation.  The comment period for the proposed rule closed on January 21, 2016.  APS and PNM filed separate comments with EPA on EPA’s draft plan and model trading rules, advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA was to determine that it was not necessary or appropriate, the Clean Power Plan would not apply to the Navajo Nation, in which case, APS has indicated the Clean Power Plan would not have a material impact on Four Corners.  PNM is unable to predict the financial or operational impacts on Four Corners operations if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation.

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

On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order puts forth two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is affordable, reliable, safe, secure, and clean.  The order directs the EPA Administrator to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the New Source Performance Standards for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, (4) the Legal Memorandum supporting the Clean Power Plan, and (5) the New Source Performance Standards for Oil & Natural Gas Sector. 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 connection with its review, EPA filed a petition with the DC Circuit requesting that the court hold the consolidated cases challenging the Clean Power Plan in abeyance until 30 days after the conclusion of EPA’s review and any subsequent rulemaking. On April 28, 2017, the DC Circuit granted the motion to hold the consolidated cases in abeyance for 60 days, directed EPA to file status reports every 30 days, and ordered the parties to file supplemental briefs by May 15, 2017, addressing whether the cases should be remanded to EPA rather than held in abeyance.  The DC Circuit issued a similar order on the same day in connection with a motion filed by EPA to hold consolidated cases challenging the NSPS in abeyance.  EPA also signed a Federal Register notice announcing that EPA is initiating its review of the Clean Power Plan and providing advance notice of forthcoming rulemaking proceedings. The rulemaking process, if initiated, will require a period of public comment and will be subject to judicial review.

PNM’s review of the new CO₂ emission reductions standards is ongoing and the assessment of its impacts will depend on the litigation of the final rule and actions the Trump administration is taking through judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance, if any.

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO₂,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO₂ and the 24-hour SO₂ standard. New Mexico is in attainment for the 1-hour NOx NAAQS. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO₂ NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO₂ sources to identify maximum 1-hour SO₂ concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO₂ sources through ambient monitoring or modeling. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO₂ NAAQS.  On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposes deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO₂ emissions. The settlement results from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree requires the following: (1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO₂ in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; (2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule.  SJGS and Four Corners SO₂ emissions are below the tonnages set forth in (1) above. EPA regions sent letters to state environmental agencies explaining how EPA plans to implement the consent decree.  The letters outline the schedule that EPA expects states to follow in moving forward with new SO₂ non-attainment designations. NMED did not receive a letter.

On August 11, 2015, EPA released the Data Requirements Rule for SO₂, telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO₂ NAAQS.  On June 3, 2016, NMED notified PNM that air quality modeling results indicated that SJGS was in compliance with the standard. In January 2017, NMED submitted their formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO₂ standard. In July of each year, NMED will submit an annual report to EPA documenting annual SO₂ emissions from SJGS and the associated compliance status.

On May 14, 2015, PNM received an amendment to its NSR air permit for SJGS, which reflects the revised state implementation plan for regional haze BART and requires the installation of SNCRs as described above. The revised permit also requires the reduction of 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 will help SJGS meet the NAAQS for these constituents. The BDT equipment modifications were installed at the same time as the SNCRs, in order to most efficiently and cost effectively conduct construction activities at SJGS. See Regional Haze – SJGS above.

In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 60-70 parts per billion (“ppb”). On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 ppb to 70 ppb. With ozone standards becoming more stringent, fossil-fueled generation units will come under increasing pressure to reduce emissions of NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas.

On November 10, 2015, EPA proposed a rule revising its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data are affected by events outside an area’s control. The proposed rule is timely in light of the new more stringent ozone NAAQS final rule since western states like New Mexico and Arizona are particularly subject to elevated background ozone transport from natural local sources such as wildfires, and transported via winds from distant sources, such as the stratosphere or another region or country.

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

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

PNM does not believe there will be material impacts to its facilities as a result of NMED’s nonattainment designation of the small area within Dona Ana County, but must wait on EPA’s ultimate approval, which should occur by October 1, 2017. Until EPA approves attainment designations for the Navajo Nation and releases a proposal to implement the revised ozone NAAQS, APS is unable to predict what impact the adoption of these standards may have on Four Corners. PNM cannot predict the outcome of this matter.

WEG v. OSM NEPA Lawsuit

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

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation’s authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the court granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.

Cooling Water Intake Structures

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

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

The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is in discussion with EPA regarding this issue. However, PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS. APS is currently in discussions with EPA Region 9, the NPDES permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. PNM does not expect such costs to be material.

Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants.  EPA’s proposal offered numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning waste operations.  All proposed alternatives establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. Requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits.

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

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

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

PNM facilities are not expected to be significantly impacted if the challenge to the rule is unsuccessful and the compliance deadlines remain in effect. Based upon the current requirements of the Steam Electric Effluent Guidelines Rule, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. Until a draft NPDES permit is proposed for Four Corners, APS is uncertain what will be required to comply with the finalized effluent limitations.  PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. 

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED also has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. Results of tests conducted by NMED in April 2012 and April 2013 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property.  This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels, and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. However, it is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels.  Therefore, PNM has agreed to monitor nitrate levels in a limited number of wells under the terms of the renewed discharge permit for the former generating station.  PNM is unable to predict the outcome of these matters.

Effective December 22, 2015, PNM and NMED entered into a memorandum of understanding to address changing groundwater quality conditions at the site. Under the memorandum, PNM will continue hydrocarbon investigation of the site under the supervision of NMED and qualified costs of the work will be eligible for payment through the New Mexico Corrective Action Fund (“CAF”), which is administered by the NMED Petroleum Storage Tank Bureau. Among other things, money in the CAF is available to NMED to make payments to or on behalf of owners and operators for corrective action taken in accordance with statutory and regulatory requirements to investigate, minimize, eliminate, or clean up a release. PNM’s work plan and cost estimates for specific groundwater investigation tasks were approved by the Petroleum Storage Tank Bureau. PNM submitted a monitoring plan consisting of a compilation of the data associated with the recent monitoring activities conducted under the CAF to NMED on October 3, 2016. Following NMED’s review of the data, PNM and NMED will develop plans for the next phase of work under the CAF.

Coal Combustion Byproducts Waste Disposal

CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments or landfills. The NMMMD currently regulates placement of ash, which is generated from coal combustion at SJGS, in the San Juan mine with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners.  Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office.

In June 2010, EPA published a proposed rule that included two options for waste designation of coal ash. One option was to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option was to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. 

On December 19, 2014, EPA issued its coal ash rule, including a non-hazardous waste determination for coal ash. Coal ash will be regulated as a solid waste under Subtitle D of RCRA. The rule sets minimum criteria for existing and new CCB landfills and existing and new CCB surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria; groundwater monitoring and corrective action; closure requirements and post closure care; and recordkeeping, notification, and internet posting requirements.

Because the rule is promulgated under Subtitle D, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non-compliance with the new requirements. EPA published the final CCB rule in the Federal Register on April 17, 2015, with an effective date of October 19, 2015. Based upon the requirements of the final rule, PNM conducted a CCB assessment at SJGS and made minor modifications at the plant to ensure that there are no facilities which would be considered impoundments or landfills under the rule. PNM does not expect it to have a material impact on operations, financial position, or cash flows.

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

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

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

The December 2014 CCB rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCB rules. The CCB rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in 2017 and will likely be influenced by EPA’s rule. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows. PNM would seek recovery from its ratepayers of all CCB costs that are ultimately incurred.

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are supplied by SJCC. SJCC holds certain federal, state, and private coal leases. Through January 31, 2016, SJCC was a wholly owned subsidiary of BHP and supplied processed coal for operation of SJGS under an underground coal sales agreement (“UG-CSA”) that was to expire on December 31, 2017. In addition to coal delivered to meet the current needs of SJGS, PNM prepaid SJCC for certain coal mined but not yet delivered to the plant site. At March 31, 2017 and December 31, 2016, prepayments for coal (including amounts purchased from the existing SJGS participants discussed below), which are included in other current assets, amounted to $43.0 million and $48.7 million. Additional information concerning the coal supply for SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS after the expiration of the UG-CSA. On July 1, 2015, PNM and Westmoreland Coal Company (“Westmoreland”) entered into a new coal supply agreement (“CSA”), pursuant to which Westmoreland will supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland will provide CCB disposal and mine reclamation services. Contemporaneous with the entry into the coal-related agreements, Westmoreland entered into a stock purchase agreement (the “Stock Purchase Agreement”) on July 1, 2015 to acquire all of the capital stock of SJCC. In addition, PNM, Tucson, SJCC, and SJCC’s owner entered into an agreement to terminate the existing UG-CSA upon the effective date of the new CSA.

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

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

In support of the closing under the Stock Purchase Agreement and to facilitate PNM customer savings, NM Capital, a wholly owned subsidiary of PNMR, provided funding of $125.0 million (the “Westmoreland Loan”) to Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland, to finance the purchase price of the stock of SJCC (including an insignificant affiliate) under the Stock Purchase Agreement. NM Capital was able to provide the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent. The BTMU Term Loan Agreement became effective as of February 1, 2016, has a maturity date of February 1, 2021, and bears interest at a rate based on LIBOR plus a customary spread. In connection with the BTMU Term Loan Agreement, PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. The balance outstanding under the BTMU Term Loan Agreement was $82.8 million at March 31, 2017.

The Westmoreland Loan is a $125.0 million loan agreement among NM Capital, as lender, WSJ, as borrower, SJCC and its affiliate, as guarantors, BTMU, as administrative agent, and MUFG Union Bank, N.A., as depository bank. The Westmoreland Loan became effective as of February 1, 2016, and has a maturity date of February 1, 2021. The interest rate on the Westmoreland Loan escalates over time and was initially a rate of 7.25% plus LIBOR. Such rate is 9.25% plus LIBOR for the period from February 1, 2017 through January 31, 2018. The Westmoreland Loan has been structured to encourage prepayments and early retirement of the debt. WSJ must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. In addition, the Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. At March 31, 2017, the amount outstanding under the Westmoreland Loan was $85.4 million. The next principal payment of $9.6 million plus interest of $2.2 million is due on May 2, 2017. As of April 24, 2017, $11.8 million was held in a SJCC restricted bank account that is to be used solely to service the Westmoreland Loan. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC and its affiliate. The Westmoreland Loan also includes customary representations and warranties, covenants, and events of default. There are no prepayment penalties.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds of $118.7 million with the NMMMD. In order to facilitate the posting of reclamation bonds by sureties on behalf of SJCC, PNMR entered into separate letter of credit arrangements with a bank under which letters of credit aggregating $30.3 million have been issued.

Four Corners

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to NTEC, an entity owned by the Navajo Nation, and a new coal supply contract for Four Corners, beginning in July 2016 and expiring in 2031, was entered into with NTEC. The BHP subsidiary was retained as the mine manager and operator through December 2016. Bisti Fuels Company, LLC, a subsidiary of The North American Coal Corporation, took over management and operation of the mine effective January 1, 2017. The average coal price per MMBTU under the new contract was approximately 48% higher in the second half of 2016 than in the second half of 2015. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

Coal Mine Reclamation

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

In 2015, PNM updated its final reclamation costs estimates to reflect the terms of the new reclamation services agreement with Westmoreland, discussed above, and changes resulting from the approval of the 2015 SJCC Mine Permit Plan. The 2015 reclamation cost estimate reflects that the scope and pricing structure of the reclamation service agreement with Westmoreland would significantly increase reclamation costs. In addition, design plan changes, updated regulatory expectations, and common mine reclamation practices incorporated into the 2015 SJCC Mine Permit reflect an increase in the 2015 reclamation cost estimate. The impacts of these increases, amounting to $16.5 million, were recorded at December 31, 2015.

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

Based on the 2016 estimates and PNM’s current ownership share of SJGS, PNM’s remaining payments as of March 31, 2017 for mine reclamation, in future dollars, are estimated to be $102.0 million for the surface mines at both SJGS and Four Corners and $127.8 million for the underground mine at SJGS. At March 31, 2017 and December 31, 2016, liabilities, in current dollars, of $41.5 million and $41.0 million for surface mine reclamation and $14.0 million and $14.0 million for underground mine reclamation were recorded in other deferred credits.

Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation costs associated with the supply of coal from the San Juan mine. The SJGS owners entered into a reclamation trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the UG-CSA. As part of the restructuring of SJGS ownership (see SJGS Ownership Restructuring Matters above), the SJGS owners and PNMR Development negotiated the terms of an amended agreement to fund post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable reclamation trust, and periodically deposit funds into the reclamation trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels. Based on PNM’s reclamation trust fund balance at March 31, 2017, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $6.9 million in 2017, $8.3 million in 2018, and $8.7 million in 2019.

Under the coal supply agreement for Four Corners, which became effective on July 7, 2016, PNM is required to fund its ownership share of estimated final reclamation costs in thirteen annual installments, beginning on August 1, 2016, into an irrevocable escrow account solely dedicated to the final reclamation cost of the surface mine at Four Corners. PNM’s anticipated funding level is $2.0 million, $2.1 million, and $2.1 million in 2017, 2018, and 2019.

PNM collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from retail customers for final reclamation of the surface mines at $100.0 million. Previously, PNM recorded a regulatory asset for the $100.0 million and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. Regulatory determinations made by the NMPRC may also affect the impact on PNM. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

As discussed in Note 12, PNM released a draft of its 2017 IRP on April 20, 2017. The preliminary conclusions contained in the 2017 IRP indicate that it would be cost beneficial to PNM’s customers for SJGS to be shutdown in 2022 and for PNM to exit its ownership interest in Four Corners in 2031. If the final 2017 IRP contains those same conclusions and if the NMPRC orders the abandonment of those facilities, PNM would be required to remeasure its liability for coal mine reclamation to reflect that reclamation activities would occur sooner than currently anticipated. The remeasurement would likely result in an increase in PNM’s liability under GAAP. PNM would record a regulatory asset for amounts recoverable from ratepayers under existing or future orders of the NMPRC and amounts not recoverable would be expensed. PNM cannot predict what the final 2017 IRP will conclude or what actions the NMPRC might take.

Continuous Highwall Mining Royalty Rate

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

SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS.  In March 2001, SJCC learned that the DOI Minerals Management Service (“MMS”) disagreed with the application of the underground royalty rate to CHM.  In August 2006, SJCC and MMS entered into an agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal.  The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed.  PNM’s share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM’s FPPAC. PNM is unable to predict the outcome of this matter.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with this act, the PVNGS participants are insured against public liability exposure for a nuclear incident up to $13.4 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers. The remaining $13.0 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential retrospective premium assessment per incident for all three units is $38.9 million, with a maximum annual payment limitation of $5.8 million, to be adjusted periodically for inflation.

The PVNGS participants maintain insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). A sublimit of $2.25 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium 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 2017 through 2020 has been negotiated and awaits endorsement by the parties and the New Mexico State Engineer.

In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for 40 years.

PVNGS Water Supply Litigation

In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows.

San Juan River Adjudication

In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, former President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo Nation’s water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees.  The court issued an order in August 2013 finding that no evidentiary hearing was warranted in the Navajo Nation proceeding and, on November 1, 2013, issued a Partial Final Judgment and Decree of the Water Rights of the Navajo Nation approving the proposed settlement with the Navajo Nation. Several parties filed a joint motion for a new trial, which was denied by the court. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM has entered its appearance in the appellate case. The issues have been fully briefed and the matter is pending with the New Mexico Court of Appeals.

PNM is participating in this proceeding since PNM’s water rights in the San Juan Basin may be affected by the rights recognized in the settlement agreement as being owned by the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin. PNM is unable to predict the ultimate outcome of this matter or estimate the amount or range of potential loss and cannot determine the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. Final resolution of the case cannot be expected for several years. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

Rights-of-Way Matter

On January 28, 2014, the County Commission of Bernalillo County, New Mexico passed an ordinance requiring utilities to enter into a use agreement and pay a yet-to-be-determined fee as a condition to installing, maintaining, and operating facilities on county rights-of-way. The fee is purported to compensate the county for costs of administering and maintaining the rights-of-way, as well as for capital improvements. On February 27, 2014, PNM and other utilities filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. The court denied the utilities’ motion for judgment. The court further granted the County’s motion to dismiss the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. In subsequent briefing in federal court, the County filed a motion for judgment on one of the utilities’ claims, which was granted by the court, leaving a claim regarding telecommunications service as the remaining federal claim. On January 4, 2016, the utilities filed an Application for Interlocutory Appeal from the state court, which was denied. On March 28, 2017, the utilities filed a writ of certiorari with the NM Supreme Court, which was denied. The matter will proceed in New Mexico District Court. The utilities and Bernalillo County reached a standstill agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement. If the challenges to the ordinance are unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.

Navajo Nation Allottee Matters

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

In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice.  On April 2, 2014, the allottees’ appeal was dismissed with prejudice. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments.  On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested.  The letter indicated that the renewals were not approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. On July 13, 2015, PNM filed a condemnation action in the United States District Court for the District of New Mexico regarding the approximately 15.49 acres of land at issue. On December 1, 2015, the court ruled that PNM could not condemn two of the five allotments at issue based on the Navajo Nation’s fractional interest in the land. PNM’s motion for reconsideration of this ruling was denied. On March 31, 2016, the Tenth Circuit granted PNM’s petition to appeal the December 1, 2015 ruling. On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. Both matters have been consolidated and are stayed while PNM pursues its appeal before the Tenth Circuit. On June 27, 2016, PNM filed its opening brief in the Tenth Circuit. Amicus briefs were filed in support of PNM’s position. On October 5, 2016, the United States, the Navajo Nation, and individual allottees filed their response briefs. After the response briefs were filed, other entities requested leave to file amicus briefs addressing arguments raised in the United States’ response brief. Oral argument before the Tenth Circuit was heard on January 17, 2017.

PNM cannot predict the outcome of these matters.

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Regulatory and Rate Matters

3 Months Ended

Mar. 31, 2017

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 2016 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 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. On March 2, 2016, the NMPRC required PNM to file supplemental testimony regarding the treatment of renewable energy in PNM’s FPPAC. See Renewable Portfolio Standard below. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016, pursuant to the terms of the initial sales-leaseback transactions (Note 6). A subsequent public hearing was held in June 2016. After the June hearing, PNM and other parties were ordered to file supplemental briefs and to provide final recommended revenue requirements that incorporated fuel savings that PNM implemented effective January 1, 2016 from PNM’s SJGS coal supply agreement (“CSA”).  PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current CSA (Note 11), which also reduced the request for base non-fuel related revenues by $0.2 million to $121.5 million.

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

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

• Disallowing recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying three leases of portions of PVNGS Unit 2 (Note 6); the RD proposed that power from the previously leased assets, aggregating 64.1 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expenses (other than property taxes, which were $0.8 million per year at that time), but the customers would not bear any capital or depreciation costs other than those related to improvements made after the date of the original leases

• Disallowing recovery from retail customers of the rent expense, which aggregates $18.1 million per year, under the four leases of capacity in PVNGS Unit 1 that were extended for eight years beginning January 15, 2015 and the one lease of capacity in PVNGS Unit 2 that was extended for eight years beginning January 15, 2016 (Note 6) and related property taxes, which were $1.5 million per year at that time; the RD proposed that power from the leased assets, aggregating 114.6 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expense, except that customers would not bear rental costs or property taxes

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• The final rate design

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

NEE subsequently filed a motion for a partial stay of the order at the NM Supreme Court. This motion was denied. The NM Supreme Court stated that the court’s intent was to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits. Otherwise, the court has taken no action with respect to the appeals. On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule is anticipated to be completed by June 28, 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 that a loss is to be recognized when it is probable that a loss has been incurred and the amount of loss can be reasonably estimated. When there is a range of the amount of the probable loss, the minimum amount of the range is to be accrued unless an amount within the range is a better estimate than any other amount. PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicates it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the issues, those issues would be remanded back to the NMPRC for further action. PNM estimates that it will take a minimum of 15 months, from the date PNM filed its appeal, for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order will remain in effect. PNM has concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case; that the minimum amount of loss is 15 months of capital cost recovery that the order disallowed for its investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT; and that no amount within the range of possible loss is a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million in September 2016 for the capital costs that will not be covered during that 15 month appeal period. In addition, PNM recorded a pre-tax regulatory disallowance for $4.5 million of costs recorded as regulatory assets and deferred charges (which the order disallowed and which PNM did not challenge in its appeal) since PNM can no longer assert that those assets are probable of being recovered through the ratemaking process. Additional losses will be recorded if the currently estimated 15 month time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is extended. The NMPRC’s order approved PNM’s request to record a regulatory asset to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from an extension of the income tax provision for fifty percent bonus depreciation. The impact, net of federal income taxes, amounts to $2.1 million, which was reflected as a reduction of income tax expense in September 2016.

PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurred and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is reasonably possible that its appeals will be successful, it cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record further pre-tax losses related to the capitalized costs for any unsuccessful issues. The impacts of not recovering future contributions for decommissioning would be recorded in future periods. The amounts of any such losses to be recorded would depend on the ultimate outcome of the appeal and NMPRC process, as well as the actual amounts reflected on PNM books at the time of the resolution. However, based on the book values recorded by PNM as of March 31, 2017, such losses could include:

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

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

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

Also, PNM has evaluated the accounting consequences of the issues that are being appealed by the cross-appellants. Although PNM does not believe the issues raised in the cross-appeals have substantial merit, PNM is unable to predict what decision the NM Supreme Court will reach. PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, if the Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $154.9 million (which amount includes $76.9 million that is the subject of PNM’s appeal discussed above) at March 31, 2017, after considering the loss recorded in 2016. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and prepaid pension asset in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have financial impact to PNM.

PNM is unable to predict the outcome of this matter.

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

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

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

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

• ROE of 10.125%

• Drivers of revenue deficiency

◦ Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (Note 11)

◦ Infrastructure investments, including environmental upgrades at Four Corners

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

◦ Updates in the FERC/retail jurisdictional allocations

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

◦ Increased customer and demand charges

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

The NMPRC scheduled a public hearing to begin on June 5, 2017, ordered that a settlement conference should be held, and that any resulting stipulation should be filed by March 27, 2017. Settlement discussions have been held, but no agreements were reached by March 27, 2017. PNM and several intervenors filed an unopposed motion with the NMPRC to extend by one month the procedural schedule, including the date for filing a stipulation. On April 12, 2017, the NMPRC issued an order modifying the procedural schedule to allow for additional settlement discussion. Under the revised schedule, any settlement stipulation was to be filed by April 27, 2017 and the public hearing would begin on July 10, 2017. On April 27, 2017, PNM and several intervenors filed a motion with the NMPRC to extend the deadline for filing a stipulation to May 5, 2017. The motion is subject to approval by the Hearing Examiner. Upon filing, a settlement would require the approval of the NMPRC in order to take effect. PNM cannot predict the outcome of this matter.

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 Staff on the one hand, and the utilities on the other.” The order posed the following questions: whether a standardized method (“DCF”) 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. A procedural schedule has been established that includes initial comments on July 10, 2017 and a public workshop on August 9, 2017. PNM cannot predict the outcome of this proceeding.

Renewable Portfolio Standard

The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. PNM files annual renewable energy procurement plans for approval by the NMPRC. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are minimums of 30% wind, 20% solar, 3% distributed generation, and 5% other.

The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures that utilities recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges. PNM makes renewable procurements consistent with the NMPRC approved plans. PNM recovers certain renewable procurement costs from customers through a rate rider. See Renewable Energy Riderbelow.

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

• 107 MW of PNM-owned solar PV facilities, including 40 MW constructed in 2015 that were identified as a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11) and are being recovered in the base rates provided in the NM 2015 Rate Case discussed above rather than through PNM’s renewable energy rider; and an additional procurement of 1.5 MW of PNM-owned solar PV facilities to supply the energy sold under PNM’s voluntary renewable energy tariff

• A PPA through 2027 for the output of New Mexico Wind, having an aggregate capacity of 204 MW and a PPA through 2035 for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW

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

• Solar distributed generation, aggregating 66.8 MW at March 31, 2017, owned by customers or third parties from whom PNM purchases any net excess output and RECs

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

PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan met RPS and diversity requirements within the RCT in 2016 and 2017 using existing resources and did not propose any significant new procurements. The NMPRC approved the plan in November 2015, and, after granting a rehearing motion to consider issues regarding the rate treatment of certain customers eligible for a cap on, or an exemption from, RPS procurement, the NMPRC again approved the plan in an order issued on February 3, 2016. The NMPRC deferred issues related to capped and exempt customers to PNM’s NM 2015 Rate Case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The NM 2015 Rate Case and show cause proceeding were to examine whether PNM miscalculated the FPPAC factor and base fuel costs in its treatment of renewable energy costs and application of the renewable procurement cost caps and exemptions. The show cause proceeding was stayed pending the outcome of the NM 2015 Rate Case. The September 28, 2016 order in the NM 2015 Rate Case directed that the cost of New Mexico Wind be recovered through PNM’s renewable rider, rather than the FPPAC, and ordered certain other modifications regarding the accounting for renewable energy in PNM’s FPPAC. These modifications do not affect the amount of fuel and purchased power or renewable costs that PNM will collect. No action has been taken in the show cause proceeding and PNM cannot predict its outcome.

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

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In PNM’s NM 2015 Rate Case, the NMPRC authorized continuation of the renewable rider. PNM recorded revenues from the rider of $11.0 million and $8.4 million in the three months ended March 31, 2017 and 2016.

In its 2016 renewable energy procurement plan case, PNM proposed to collect $42.4 million in 2016. The 2016 rider adjustment was approved as part of the order issued February 3, 2016 approving the 2016 renewable energy plan. In its 2017 renewable energy procurement plan, PNM proposed to collect $50.0 million through the rider in 2017. The increase, as compared with the amount the NMPRC approved for recovery through the rider in 2016, was due to recovering the costs of energy from New Mexico Wind through the rider, rather than through the FPPAC in compliance with the NMPRC’s order in PNM’s NM 2015 Rate Case. The 2017 rider adjustment was approved in the November 23, 2016 order that approved the 2017 renewable energy plan. On February 28, 2017, PNM filed a reconciliation of 2017 revenue requirement and proposed a revision to the rider that would recover $42.7 million during 2017.

Under the renewable rider, if PNM’s earned rate of return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM is required to refund the excess to customers during May through December of the following year. PNM’s annual compliance filings with the NMPRC show that its rate of return on jurisdictional equity did not exceed the limitation through 2016.

Energy Efficiency and Load Management

Program Costs and Incentives

Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. The act sets an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s costs to implement approved programs are recovered through a rate rider.

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

On April 14, 2017, PNM filed an application for energy efficiency and load management programs to be offered in 2018. The proposed program portfolio consists of a continuation of the ten programs approved in the 2016 application with a total budget of $25.1 million. The application also seeks approval of a sliding scale incentive with a base incentive of $1.9 million if PNM is able to achieve saving of 53 GWh in 2018. PNM projects it would earn an incentive of $2.1 million based on targeted savings of 70 GWh. The actual incentive would be based on actual savings achieved. The application also requests a variance if the NMPRC approves a pending rulemaking that would reduce the frequency of energy efficiency applications to every other year so that PNM would not have to file its next energy efficiency application until 2019. PNM proposes to continue the same ten programs and a similar incentive mechanism in 2019, with a proposed budget of $28.2 million and a base level incentive of $2.1 million. PNM is unable to predict the outcome of this proceeding.

Energy Efficiency Rulemaking

In July 2012, the NMPRC opened an energy efficiency rulemaking docket to potentially address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

On January 25, 2017, the NMPRC opened another energy efficiency rulemaking docket to consider whether applications for approval of energy efficiency and load management programs should be filed every two years rather than annually. Written comments were filed in the rulemaking docket, and a public comment hearing was held on March 31, 2017. PNM is unable to 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. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term resource needs with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the then pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they asserted that the IRP did not conform to the NMPRC’s IRP rule. Certain parties also asked that further proceedings on the IRP be held in abeyance until the conclusion of the SJGS abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that docketed a case to determine whether the IRP complied with applicable NMPRC rules. The order also held the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3. The order regarding PNM’s application to abandon SJGS Units 2 and 3 described in Note 11 states that the NMPRC will issue a Notice of Proposed Dismissal in the 2014 IRP docket. On May 4, 2016, the NMPRC issued the Notice of Proposed Dismissal, stating that the docket 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 IRP in abeyance or to dismiss those protests without prejudice. PNM responded on June 13, 2016 and requested that the NMPRC dismiss the case with prejudice. The NMPRC has not yet acted on its Notice of Proposed Dismissal or the request filed on May 31, 2016. PNM cannot predict the outcome of this matter.

2017 IRP

The 2017 IRP will address a 20-year planning period, from 2017 through 2036, and will include an action plan describing PNM’s plan to implement the 2017 IRP in the four-year period following its filing. PNM held its initial public advisory meeting on the 2017 IRP on June 30, 2016. The public advisory process is proceeding in three phases: in the first, PNM will build assumptions and discuss scenarios and sensitivities; in the second, PNM will discuss its analysis; and in the third, PNM will discuss its draft IRP with the public advisory participants. PNM intends to file its 2017 IRP by July 3, 2017, within the time limit prescribed by NMPRC rule. The NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 11 requires PNM to make a filing in 2018 to determine the extent to which SJGS Units 1 and 4 should continue serving PNM’s retail customers’ needs after June 30, 2022. To facilitate the 2018 filing, PNM is developing two resource portfolios in the 2017 IRP, one with SJGS continuing beyond mid-2022 and one where it is shut down. On March 17, 2017, PNM announced that preliminary results of its analysis indicate that retirement of SJGS in 2022 could be cost-effective for customers.

On April 20, 2017, PNM released a draft of the 2017 IRP. Key findings in that draft 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 built from Eastern New Mexico to PNM’s service territory

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

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

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

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

• PNM should pursue securitization legislation to provide additional customer cost savings and provide funds for replacement resources

The draft of the 2017 IRP sets forth the results of the IRP process to date. Additional input through a continuing public advisory process could lead to further analysis of the resource mix, which could result in revisions from the draft plan. PNM must file the final IRP by July 3, 2017. PNM cannot predict the ultimate outcome of the 2017 IRP process or whether the NMPRC will approve subsequent filings that would encompass actions to implement the conclusions of the 2017 IRP.

San Juan Generating Station Units 2 and 3 Retirement

On December 16, 2015, the NMPRC issued an order approving PNM’s retirement of SJGS Units 2 and 3 on December 31, 2017. On January 14, 2016, NEE filed an appeal of the order with the NM Supreme Court. Additional information concerning the NMPRC filing and related proceedings is set forth in Note 11.

Application for Certificate of Convenience and Necessity

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

Advanced Metering Infrastructure Application

On February 26, 2016, PNM filed an application with the NMPRC requesting approval of a project to replace its existing customer metering equipment with Advanced Metering Infrastructure (“AMI”). The application also asks the NMPRC to authorize the recovery of the cost of the project, up to $87.2 million, in future ratemaking proceedings, as well as to approve the recovery of the remaining undepreciated investment in existing metering equipment estimated to be approximately $33 million at the date of implementation and the costs of customer education and severances for affected employees. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. On August 5, 2016, PNM filed a motion to suspend its AMI application so that it could evaluate the effect of the order in the NM 2015 Rate Case. The NMPRC approved this motion. On November 22, 2016, PNM filed a motion to lift the suspension and establish a new procedural schedule. In December 2016, the Hearing Examiner issued an order lifting the suspension and issued a new procedural schedule. Hearings in this matter were held in February and March 2017. The Hearing Examiner has required submission of additional testimony related to the meter contractor’s compliance with construction industries licensure requirements and may schedule a further hearing. PNM cannot predict the outcome of this matter.

Facebook Data Center Project

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

• Two new electric service rates

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

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

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

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

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

Hazard Sharing Agreement

On June 1, 2016, PNM and Tri-State entered into a one-year hazard sharing agreement, which expires on May 31, 2017.  Under the agreement, each party will sell the other party 100 MW of capacity and energy on a unit contingent basis, from each party’s designated primary resources, which is SJGS Unit 4 for PNM and Springerville Generating Station Unit 3 for Tri-State.  Both purchases and sales are made at the same market index price.  In 2016, PNM sold 482,342 MWh for $12.8 million and purchased 484,632 MWh for $12.9 million under the agreement. In the three months ended March 31, 2017, PNM sold 213,533 MWh for $4.8 million and purchased 205,156 MWh for $4.6 million under the agreement. The agreement serves to reduce the magnitude of each party’s single largest generating hazard and assists in enhancing the reliability and efficiency of their respective operations. PNM and Tri-State have entered into an additional agreement, under substantially identical terms, for a term of five years beginning June 1, 2017, subject to NMPRC approval. NMPRC approval was not required for the one-year agreement, but is required for the five-year agreement. On November 30, 2016, PNM filed an application with the NMPRC for approval of the five-year agreement. A public hearing on PNM’s request was held on March 23, 2017. On April 26, 2017, the Hearing Examiner in the case issued a recommended decision that would approve PNM’s application. PNM cannot predict the outcome of this matter.

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

As discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, NEC filed a petition on April 8, 2015 for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under its PSA with PNM. Following proceedings before a settlement judge, PNM and NEC entered into, and filed with FERC, a settlement agreement on October 29, 2015 that includes certain amendments to the PSA and related contracts on file with FERC. FERC approved the settlement on January 21, 2016. Under the settlement agreement, PNM served all of NEC’s load in 2016 at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC also paid certain third-party transmission costs that it only partially paid previously. The PSA and related transmission agreements terminated on December 31, 2016. In 2017, PNM is serving 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. Amounts billed to NEC were $1.1 million and $5.4 million in the three months ended March 31, 2017 and 2016. PNM’s NM 2016 Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve NEC.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011. TNMP completed its mass deployment in 2016 and has installed more than 242,000 advanced meters.

The PUCT adopted a rule creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service is to be borne by opt-out customers through an initial fee and ongoing monthly charge. As approved by the PUCT, TNMP is recovering $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million through a $36.78 monthly fee. These amounts presume up to 1,081 consumers will elect the non-standard meter service, but TNMP has the right to adjust the fees if the number of anticipated consumers differs from that estimate. As of April 24, 2017, 103 consumers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

Transmission Cost of Service Rates

TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s recent interim transmission cost rate increases:

Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 10, 2015	$	7.0	$	1.4
March 23, 2016	25.8		4.3
September 8, 2016	9.5		1.8
March 14, 2017	30.2		4.8

On March 23, 2017, the PUCT staff filed proposed amendments to the interim TCOS filing rule. If approved, the amendments could reduce the frequency of such filings to once per year. The amendments could also reduce the amount recovered by requiring that changes in accumulated deferred income taxes be considered and would preclude filings by utilities earning more than their authorized rate of return using weather-normalized data. The PUCT has not yet approved the amendments for publication. Initial comments on the proposed rule will be due 30 days after publication. TNMP cannot predict the outcome of this matter.

Periodic Distribution Rate Adjustment

PUCT rules permit interim rate adjustments to reflect changes in investments in distribution assets. Distribution utilities may file for a periodic rate adjustment between April 1 and April 8 of each year as long as the electric utility is not earning more than its authorized rate of return using weather-normalized data. However, TNMP has not made a filing to adjust rates for additional investments in distribution assets. In connection with TNMP’s deployment of its advance meter system discussed above, TNMP committed to file a general rate case no later than September 1, 2018. TNMP has also committed that it would not file a request for an increase in rates to reflect changes in investments in distribution assets until after the 2018 general rate case.

Competition Transition Charge Compliance Filing

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

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Income Taxes

3 Months Ended

Mar. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

In 2013, New Mexico House Bill 641 reduced the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction is being phased-in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment, which was in the year ended December 31, 2013. At that time, the portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. In addition, the portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax expense. Changes in the estimated timing of reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2017 and 2016, PNM’s regulatory liability was reduced by $4.8 million and $7.1 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: reduced by $0.1 million in the three months ended March 31, 2017, increasing income tax expense by less than $0.1 million for PNM and $0.1 million for the Corporate and Other segment; and decreased by $0.7 million in the three months ended March 31, 2016, increasing income tax expense by $0.8 million for PNM and reducing income tax expense by $0.1 million for the Corporate and Other segment. See Note 8 for a discussion of the impacts on income tax expense resulting from the adoption of Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718).

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Related Party Transactions

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP, as is PNMR Services Company, a wholly-owned subsidiary of PNMR that provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

	Three Months Ended
	March 31,
	2017		2016
	(In thousands)
Services billings:
PNMR to PNM	$	24,402	$	22,734
PNMR to TNMP	8,137		7,048
PNM to TNMP	85		106
TNMP to PNMR	35		10
Interest billings:
PNMR to TNMP	31		50
PNM to PNMR	43		36
Income tax sharing payments:
PNMR to PNM	—		—
PNMR to TNMP	—		—

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Significant Accounting Policies and Responsibility for Financial Statements (Policies)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Principles of Consolidation

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 5) and, through January 15, 2016, the PVNGS Capital Trust. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.

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

New Accounting Pronouncements

New Accounting Pronouncements

Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below.

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

In May 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. When it becomes effective, the new standard will replace most existing revenue recognition guidance in GAAP. Since the issuance of ASU No. 2014-09, the FASB issued a one-year deferral in the effective date and has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. The new standard can be applied retrospectively to each prior period presented or on a modified retrospective basis with a cumulative effect adjustment to retained earnings on the date of adoption. The Company has not made a final decision on the transition method, but currently anticipates using the modified retrospective method. The Company will adopt the standard on January 1, 2018, its required effective date.

The Company has completed its initial assessment and made significant progress toward completing the evaluation of its revenues for potential changes to the amounts and timing of revenue recognition under the new guidance. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification. These industry specific issues include the impacts of the new guidance on its accounting for CIAC, collectability, and the presentation of revenues associated with “alternative revenue programs,” which primarily result from its approved rate rider programs. The Company is working towards completing its evaluation and drafting its revenue recognition disclosures under the new standard. The Company has not finalized conclusions and has not yet completely determined the effect of the standard on its financial reporting, but does not anticipate significant changes in revenue recognition associated with retail electric service rates or expect difficulty in completing this project by the required January 1, 2018 implementation date.

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

In January 2016, the FASB issued ASU No. 2016-01, which makes targeted improvements to GAAP regarding financial instruments. The new standard eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and will require those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. Also, the new standard will revise certain presentation and disclosure requirements. Under the new standard, accounting for investments in debt securities remains essentially unchanged. PNM currently classifies the investments held in the NDT and coal mine reclamation trusts as available for sale securities. Unrealized losses on these securities are recorded immediately through earnings and unrealized gains are recorded in AOCI until the securities are sold. The Company will adopt the new standard on January 1, 2018, its required effective date. At that time any unrealized gains, net of income taxes, recorded in AOCI related to equity securities will be reclassified to retained earnings as a cumulative effect adjustment and, thereafter, changes in the value of equity securities will be recorded in the Consolidated Statements of Earnings. The amount of the cumulative adjustment upon adoption will depend on the amounts recorded in AOCI at that time, but PNM had unrealized gains on equity securities, net of income taxes, recorded in AOCI of $6.8 million at March 31, 2017.

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

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

As discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, the Company has operating leases of office buildings, vehicles, equipment, and certain rights-of-way. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification. The Company has formed a project team, conducted outreach activities across its lines of business, and made significant progress in identifying arrangements, in addition to its existing operating lease arrangements, that may be classified as leases under the ASU. It is likely the arrangements currently classified as leases will continue to be recognized as leases under the new ASU. It is possible that other contractual arrangements not previously meeting the lease definition may contain elements that qualify as leases under ASU 2016-02 and that previously identified operating leases may be classified as financing leases under the new standard. The Company is in the process of analyzing each of the identified contractual arrangement to determine if it contains lease elements under the new standard and to quantify the potential impacts of identified lease arrangements. The Company anticipates this process will continue through the remainder of 2017 and possibly into 2018. Upon completion of that process, the Company will provide additional information about the expected financial impact of this ASU.

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

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

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

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

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

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

Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350)

In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. 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 this ASU 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 must adopt this ASU in 2020, but early adoption is permitted. The Company currently anticipates adopting this ASU in 2020. However, if there is an indication of potential impairment of goodwill as a result of an annual impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this ASU.

Accounting Standards Update 2017-07 – Compensation – Retirement Benefits (Topic 715)

In March 2017, the FASB issued ASU 2017-07 to improve the presentation of net periodic pension and other postretirement benefit costs. Currently, the Company presents all of its net periodic benefit costs as administrative and general expenses on its Condensed Consolidated Statements of Earnings, net of amounts capitalized to construction and other accounts. The amendments in this ASU require the service cost component of net benefit costs be presented in the same line item or items as compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of operating income with disclosures identifying where the other components of net benefit cost have been presented. The ASU also limits capitalization to only the service cost component of benefit costs. PNMR and its subsidiaries maintain qualified defined benefit pension and OPEB plans. Currently, net periodic benefit cost for the Company’s defined benefit pension plans do not include a service cost component and there is only a minor amount of service cost for the OPEB plans. Additional information about the Company’s plans is discussed in Note 12 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 10. The ASU requires retrospective presentation of the service cost component and the other components of net benefit cost in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit cost. The Company must adopt this ASU beginning January 1, 2018. The Company is in the process of analyzing the impacts of this new standard, including the treatment of benefit costs by the NMPRC, PUCT, and FERC in the regulatory process.

Accounting Standards Update 2017-08 - Receivables - Nonrefundable Fees and Other Costs (Topic 310-20) Premium Amortization on Purchased Callable Debt Securities

In March 2017, the FASB issued ASU No. 2017-08. The ASU amends the amortization period for certain purchased callable debt securities held at a premium. Under current GAAP, some entities amortize the premium as an adjustment of yield over the contractual life of the security. The update requires premiums to be amortized over the period to the earliest call date. The new standard is effective for the Company beginning on January 1, 2019. Early adoption is permitted including adoption in an interim period. The Company is in the process of analyzing the impacts of this new standard.

The FASB issued Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718) to simplify several aspects of the accounting for share-based payment transactions and eliminate diversity in practice. PNMR’s historical accounting for stock compensation complies with ASU 2016-09, except for the treatment of the income tax consequences of awards and the presentation of reductions to taxes payable on the Consolidated Statements of Cash Flows. Prior to ASU 2016-09, benefits resulting from income tax deductions in excess of compensation cost recognized under GAAP for vested restricted stock and on exercised stock options (“excess tax benefits”) were recorded to equity provided the excess tax benefits reduced income taxes payable. Deficiencies resulting from tax deductions related to stock awards that were below recognized compensation cost upon vesting and on canceled stock options were recorded to equity. PNMR has not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. ASU 2016-09 requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as cash flows from operating activities.

Variable Interest Entity

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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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2017

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,
	2017		2016
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	22,862	$	10,546
Average Number of Common Shares:
Outstanding during period	79,654		79,654
Vested awards of restricted stock	112		104
Average Shares – Basic	79,766		79,758
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	346		406
Average Shares – Diluted	80,112		80,164
Net Earnings Per Share of Common Stock:
Basic	$	0.29	$	0.13
Diluted	$	0.29	$	0.13

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2017

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			Consolidated
	(In thousands)
Three Months Ended March 31, 2017
Electric operating revenues	$	251,558		$	78,620		$	—		$	330,178
Cost of energy	81,317			21,487			—			102,804
Utility margin	170,241			57,133			—			227,374
Other operating expenses	95,894			23,797			(4,660		)	115,031
Depreciation and amortization	36,016			15,371			4,996			56,383
Operating income (loss)	38,331			17,965			(336		)	55,960
Interest income	2,816			—			2,065			4,881
Other income (deductions)	7,683			732			(335		)	8,080
Interest charges	(21,012		)	(7,404		)	(3,284		)	(31,700		)
Segment earnings (loss) before income taxes	27,818			11,293			(1,890		)	37,221
Income taxes (benefit)	7,708			3,689			(622		)	10,775
Segment earnings (loss)	20,110			7,604			(1,268		)	26,446
Valencia non-controlling interest	(3,452		)	—			—			(3,452		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	16,526		$	7,604		$	(1,268	)	$	22,862
At March 31, 2017:
Total Assets	$	4,870,201		$	1,396,055		$	211,423		$	6,477,679
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended March 31, 2016
Electric operating revenues	$	235,606		$	75,355		$	—		$	310,961
Cost of energy	72,444			19,925			—			92,369
Utility margin	163,162			55,430			—			218,592
Other operating expenses	108,001			22,368			(3,114		)	127,255
Depreciation and amortization	31,864			14,508			3,457			49,829
Operating income (loss)	23,297			18,554			(343		)	41,508
Interest income	1,522			—			2,100			3,622
Other income (deductions)	7,943			608			(1,068		)	7,483
Interest charges	(21,591		)	(7,369		)	(2,531		)	(31,491		)
Segment earnings (loss) before income taxes	11,171			11,793			(1,842		)	21,122
Income taxes (benefit)	3,610			4,337			(790		)	7,157
Segment earnings (loss)	7,561			7,456			(1,052		)	13,965
Valencia non-controlling interest	(3,287		)	—			—			(3,287		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	4,142		$	7,456		$	(1,052	)	$	10,546
At March 31, 2016:
Total Assets	$	4,719,346		$	1,312,402		$	242,064		$	6,273,812
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2017

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2017 and 2016 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, 2016	$	4,320		$	(96,748	)	$	(92,428	)	$	(23	)	$	(92,451	)
Amounts reclassified from AOCI (pre-tax)	(2,763		)	1,618			(1,145		)	112			(1,033		)
Income tax impact of amounts reclassified	1,078			(631		)	447			(44		)	403
Other OCI changes (pre-tax)	7,766			—			7,766			(185		)	7,581
Income tax impact of other OCI changes	(3,030		)	—			(3,030		)	72			(2,958		)
Net after-tax change	3,051			987			4,038			(45		)	3,993
Balance at March 31, 2017	$	7,371		$	(95,761	)	$	(88,390	)	$	(68	)	$	(88,458	)

Balance at December 31, 2015	$	17,346		$	(88,822	)	$	(71,476	)	$	44		$	(71,432	)
Amounts reclassified from AOCI (pre-tax)	(11,210		)	1,376			(9,834		)	146			(9,688		)
Income tax impact of amounts reclassified	4,374			(537		)	3,837			(57		)	3,780
Other OCI changes (pre-tax)	5,458			—			5,458			(1,289		)	4,169
Income tax impact of other OCI changes	(2,130		)	—			(2,130		)	503			(1,627		)
Net after-tax change	(3,508		)	839			(2,669		)	(697		)	(3,366		)
Balance at March 31, 2016	$	13,838		$	(87,983	)	$	(74,145	)	$	(653	)	$	(74,798	)

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Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2017

Variable Interest Entities [Abstract]

Summarized Financial Information

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended March 31,
	2017			2016
	(In thousands)
Operating revenues	$	4,927		$	4,937
Operating expenses	(1,475		)	(1,650		)
Earnings attributable to non-controlling interest	$	3,452		$	3,287

Financial Position

	March 31,		December 31,
	2017		2016
	(In thousands)
Current assets	$	2,841	$	2,551
Net property, plant, and equipment	66,237		66,947
Total assets	69,078		69,498
Current liabilities	734		578
Owners’ equity – non-controlling interest	$	68,344	$	68,920

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Fair Value of Derivative and Other Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value of Derivative and Other Financial Instruments [Abstract]

Summary of Derivatives

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

	Economic Hedges
	March 31, 2017			December 31, 2016
PNMR and PNM	(In thousands)
Current assets	$	4,586		$	5,224
Current liabilities	(360		)	(2,339		)
Net	$	4,226		$	2,885

Effect of Mark-to-Market on Earnings, Excluding Tax Effects

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

	Economic Hedges
	Three Months Ended
	March 31,
	2017		2016
PNMR and PNM	(In thousands)
Electric operating revenues	$	3,341	$	2,684
Cost of energy	11		(145		)
Total gain (loss)	$	3,352	$	2,539

Schedule of Net Buy (Sell) Volume Positions

The table below presents PNMR’s and PNM’s net buy (sell) volume positions:

	Economic Hedges
	MMBTU	MWh
PNMR and PNM
March 31, 2017	100,000	(1,834,125	)
December 31, 2016	254,100	(2,471,600	)

Schedule of Fair Value and Gross Unrealized Gains in Available-for-sale Securities

The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	March 31, 2017				December 31, 2016
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	8,047	$	—	$	23,683
Equity securities:
Domestic value	3,044		70,043		1,135		34,796
Domestic growth	4,438		65,127		3,032		47,595
International and other	3,555		36,442		2,029		27,481
Fixed income securities:
U.S. Government	178		31,410		115		40,962
Municipals	617		33,218		585		43,789
Corporate and other	574		41,812		553		54,671
	$	12,406	$	286,099	$	7,449	$	272,977

Schedule of Gross Realized Gains and Losses

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the decrease in realized impairment losses of$1.1 millionand $1.6 million for the three months ended March 31, 2017 and 2016.

	Three Months Ended
	March 31,
	2017			2016
PNMR and PNM	(In thousands)
Proceeds from sales	$	266,388		$	124,900
Gross realized gains	$	8,645		$	10,716
Gross realized (losses)	$	(3,085	)	$	(6,116	)

Investments Classified by Contractual Maturity Date

At March 31, 2017, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR
	(In thousands)
Within 1 year	$	3,852	$	—
After 1 year through 5 years	23,629		96,444
After 5 years through 10 years	29,024		—
After 10 years through 15 years	3,963		—
After 15 years through 20 years	8,728		—
After 20 years	37,244		—
	$	106,440	$	96,444

Schedule of Investments

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at March 31, 2017 and December 31, 2016 for items recorded at fair value.

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
PNMR and PNM	(In thousands)
March 31, 2017
Available-for-sale securities
Cash and cash equivalents	$	8,047		$	8,047	$	—
Equity securities:
Domestic value	70,043			70,043		—
Domestic growth	65,127			65,127		—
International and other	36,442			33,212		3,230
Fixed income securities:
U.S. Government	31,410			30,179		1,231
Municipals	33,218			—		33,218
Corporate and other	41,812			—		41,812
	$	286,099		$	206,608	$	79,491
Commodity derivative assets	$	4,586		$	—	$	4,586
Commodity derivative liabilities	(360		)	—		(360		)
Net	$	4,226		$	—	$	4,226
December 31, 2016
Available-for-sale securities
Cash and cash equivalents	$	23,683		$	23,683	$	—
Equity securities:
Domestic value	34,796			34,796		—
Domestic growth	47,595			47,595		—
International and other	27,481			27,481		—
Fixed income securities:
U.S. Government	40,962			39,723		1,239
Municipals	43,789			—		43,789
Corporate and other	54,671			23,158		31,513
	$	272,977		$	196,436	$	76,541
Commodity derivative assets	$	5,224		$	—	$	5,224
Commodity derivative liabilities	(2,339		)	—		(2,339		)
Net	$	2,885		$	—	$	2,885

Schedule of Carrying Amount and Fair Value of Items Not Recorded at Fair Value

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

					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
March 31, 2017	(In thousands)
PNMR
Long-term debt	$	2,384,160	$	2,525,916	$	—	$	2,525,916	$	—
Westmoreland Loan	$	85,410	$	96,444	$	—	$	—	$	96,444
Other investments	$	419	$	1,051	$	419	$	—	$	632
PNM
Long-term debt	$	1,631,972	$	1,728,276	$	—	$	1,728,276	$	—
Other investments	$	188	$	188	$	188	$	—	$	—
TNMP
Long-term debt	$	420,950	$	464,877	$	—	$	464,877	$	—
Other investments	$	231	$	231	$	231	$	—	$	—
December 31, 2016
PNMR
Long-term debt	$	2,392,712	$	2,540,693	$	—	$	2,540,693	$	—
Westmoreland Loan	$	95,000	$	100,893	$	—	$	—	$	100,893
Other investments	$	547	$	1,164	$	547	$	—	$	617
PNM
Long-term debt	$	1,631,369	$	1,730,157	$	—	$	1,730,157	$	—
Other investments	$	316	$	316	$	316	$	—	$	—
TNMP
Long-term debt	$	420,875	$	468,329	$	—	$	468,329	$	—
Other investments	$	231	$	231	$	231	$	—	$	—

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Stock-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2017

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	2017		2016
Weighted-average grant date fair value	$	22.12	$	26.05
Total fair value of restricted shares that vested (in thousands)	$	5,024	$	4,131
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)	$	945	$	853

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	2017			2016
Expected quarterly dividends per share	$	0.2425		$	0.2200
Risk-free interest rate	1.58		%	1.00		%
Market-Based Shares
Dividend yield	2.67		%	2.74		%
Expected volatility	20.80		%	20.44		%
Risk-free interest rate	1.54		%	0.97		%

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, 2017:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2016	218,316		$	27.59	305,874		$	12.29
Granted	231,107		$	22.12	—		$	—
Exercised	(248,003	)	$	20.26	(59,600	)	$	18.66
Forfeited	(822	)	$	27.86	—		$	—
Expired	—		$	—	(3,000	)	$	30.50
Outstanding at March 31, 2017	200,598		$	30.35	243,274		$	10.51

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Financing (Tables)

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Schedule of Short-term Debt

Short-term debt outstanding consisted of:

	March 31,		December 31,
Short-term Debt	2017		2016
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	16,200	$	35,000
PNM New Mexico Credit Facility	—		26,000
TNMP Revolving Credit Facility	22,000		—
PNMR:
PNMR Revolving Credit Facility	164,900		126,100
PNMR 2016 One-Year Term Loan	100,000		100,000
	$	303,100	$	287,100

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Pension and Other Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2017

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs

The following tables present the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2017			2016			2017			2016			2017		2016
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	24		$	35		$	—	$	—
Interest cost	6,727			7,577			1,006			1,087			174		203
Expected return on plan assets	(8,451		)	(8,854		)	(1,308		)	(1,371		)	—		—
Amortization of net (gain) loss	4,001			3,455			921			286			78		64
Amortization of prior service cost	(241		)	(241		)	(416		)	(7		)	—		—
Net periodic benefit cost	$	2,036		$	1,937		$	227		$	30		$	252	$	267

The following tables present the components of the TNMP Plans’ net periodic benefit cost (income):

	Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2017			2016			2017			2016			2017		2016
	(In thousands)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	—		$	—		$	36		$	46		$	—	$	—
Interest cost	722			826			139			169			8		10
Expected return on plan assets	(945		)	(986		)	(114		)	(122		)	—		—
Amortization of net (gain) loss	231			175			(20		)	(10		)	2		1
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost (Income)	$	8		$	15		$	41		$	83		$	10	$	11

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Regulatory and Rate Matters (Tables)

3 Months Ended

Mar. 31, 2017

Regulated Operations [Abstract]

Schedule of Rate Increases for Transmission Costs

such facilities. The following sets forth TNMP’s recent interim transmission cost

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

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

	Three Months Ended
	March 31,
	2017		2016
	(In thousands)
Services billings:
PNMR to PNM	$	24,402	$	22,734
PNMR to TNMP	8,137		7,048
PNM to TNMP	85		106
TNMP to PNMR	35		10
Interest billings:
PNMR to TNMP	31		50
PNM to PNMR	43		36
Income tax sharing payments:
PNMR to PNM	—		—
PNMR to TNMP	—		—

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Significant Accounting Policies and Responsibility for Financial Statements (Details)	Mar. 31, 2017 USD ($)
Accounting Policies [Abstract]
Payment defaults under agreements	$ 0
Unrealized gains, net of income taxes, recorded in AOCI	$ 6,800,000

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Net Earnings Attributable to PNMR	$ 22,862	$ 10,546
Average Number of Common Shares:
Outstanding during period (in shares)	79,654	79,654
Vested awards of restricted stock (in shares)	112	104
Average Shares – Basic (in shares)	79,766	79,758
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock (in shares)	346	406
Average Shares – Diluted (in shares)	80,112	80,164
Net Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 0.29	$ 0.13
Diluted (in dollars per share)	$ 0.29	$ 0.13

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Segment Information - Summarized Financial Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	$ 330,178	$ 310,961
Cost of energy	102,804	92,369
Utility margin	227,374	218,592
Other operating expenses	115,031	127,255
Depreciation and amortization	56,383	49,829
Operating income	55,960	41,508
Interest income	4,881	3,622
Other income (deductions)	8,080	7,483
Interest charges	(31,700)	(31,491)
Earnings before Income Taxes	37,221	21,122
Income taxes (benefit)	10,775	7,157
Net Earnings	26,446	13,965
Valencia non-controlling interest	(3,452)	(3,287)
Subsidiary preferred stock dividends	(132)	(132)
Net Earnings Available for PNM Common Stock	22,862	10,546
Total Assets	6,477,679	6,273,812	$ 6,471,080
Goodwill	278,297	278,297	$ 278,297
PNM
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	251,558	235,606
Cost of energy	81,317	72,444
Utility margin	170,241	163,162
Other operating expenses	95,894	108,001
Depreciation and amortization	36,016	31,864
Operating income	38,331	23,297
Interest income	2,816	1,522
Other income (deductions)	7,683	7,943
Interest charges	(21,012)	(21,591)
Earnings before Income Taxes	27,818	11,171
Income taxes (benefit)	7,708	3,610
Net Earnings	20,110	7,561
Valencia non-controlling interest	(3,452)	(3,287)
Subsidiary preferred stock dividends	(132)	(132)
Net Earnings Available for PNM Common Stock	16,526	4,142
Total Assets	4,870,201	4,719,346
Goodwill	51,632	51,632
TNMP
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	78,620	75,355
Cost of energy	21,487	19,925
Utility margin	57,133	55,430
Other operating expenses	23,797	22,368
Depreciation and amortization	15,371	14,508
Operating income	17,965	18,554
Interest income	0	0
Other income (deductions)	732	608
Interest charges	(7,404)	(7,369)
Earnings before Income Taxes	11,293	11,793
Income taxes (benefit)	3,689	4,337
Net Earnings	7,604	7,456
Valencia non-controlling interest	0	0
Subsidiary preferred stock dividends	0	0
Net Earnings Available for PNM Common Stock	7,604	7,456
Total Assets	1,396,055	1,312,402
Goodwill	226,665	226,665
Corporate and Other
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	0	0
Cost of energy	0	0
Utility margin	0	0
Other operating expenses	(4,660)	(3,114)
Depreciation and amortization	4,996	3,457
Operating income	(336)	(343)
Interest income	2,065	2,100
Other income (deductions)	(335)	(1,068)
Interest charges	(3,284)	(2,531)
Earnings before Income Taxes	(1,890)	(1,842)
Income taxes (benefit)	(622)	(790)
Net Earnings	(1,268)	(1,052)
Valencia non-controlling interest	0	0
Subsidiary preferred stock dividends	0	0
Net Earnings Available for PNM Common Stock	(1,268)	(1,052)
Total Assets	211,423	242,064
Goodwill	$ 0	$ 0

XML

Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Equity [Abstract]
Percentage of pension liability adjustment capitalized into construction work In process	19.80%	22.70%
Percentage of pension liability adjustment capitalized into other accounts	5.40%	2.60%
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	$ (92,451)
Total Other Comprehensive Income (Loss)	3,993	$ (3,366)
Ending Balance	(88,458)
PNM
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(92,428)	(71,476)
Amounts reclassified from AOCI (pre-tax)	(1,145)	(9,834)
Income tax impact of amounts reclassified	447	3,837
Other OCI changes (pre-tax)	7,766	5,458
Income tax impact of other OCI changes	(3,030)	(2,130)
Total Other Comprehensive Income (Loss)	4,038	(2,669)
Ending Balance	(88,390)	(74,145)
PNM | Unrealized Gains on Available-for-Sale Securities
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	4,320	17,346
Amounts reclassified from AOCI (pre-tax)	(2,763)	(11,210)
Income tax impact of amounts reclassified	1,078	4,374
Other OCI changes (pre-tax)	7,766	5,458
Income tax impact of other OCI changes	(3,030)	(2,130)
Total Other Comprehensive Income (Loss)	3,051	(3,508)
Ending Balance	7,371	13,838
PNM | Pension Liability Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(96,748)	(88,822)
Amounts reclassified from AOCI (pre-tax)	1,618	1,376
Income tax impact of amounts reclassified	(631)	(537)
Total Other Comprehensive Income (Loss)	987	839
Ending Balance	(95,761)	(87,983)
PNMR
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(92,451)	(71,432)
Amounts reclassified from AOCI (pre-tax)	(1,033)	(9,688)
Income tax impact of amounts reclassified	403	3,780
Other OCI changes (pre-tax)	7,581	4,169
Income tax impact of other OCI changes	(2,958)	(1,627)
Total Other Comprehensive Income (Loss)	3,993	(3,366)
Ending Balance	(88,458)	(74,798)
PNMR | Fair Value Adjustment for Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	(23)	44
Amounts reclassified from AOCI (pre-tax)	112	146
Income tax impact of amounts reclassified	(44)	(57)
Other OCI changes (pre-tax)	(185)	(1,289)
Income tax impact of other OCI changes	72	503
Total Other Comprehensive Income (Loss)	(45)	(697)
Ending Balance	$ (68)	$ (653)

XML

Variable Interest Entities (Details) $ in Thousands		3 Months Ended
	Jan. 31, 2016 USD ($)	Mar. 31, 2017 USD ($) MW	Mar. 31, 2016 USD ($)	May 02, 2017 USD ($)	May 01, 2017 USD ($)	Apr. 24, 2017 USD ($)	Dec. 31, 2016 USD ($)
Results of Operations
Earnings attributable to non-controlling interest		$ 3,452	$ 3,287
Financial Position
Current assets		326,769					$ 378,039
Total assets		6,477,679	6,273,812				6,471,080
Current liabilities		962,136					805,108
Owners’ equity – non-controlling interest		68,344					68,920
Public Service Company of New Mexico
Results of Operations
Earnings attributable to non-controlling interest		3,452	3,287
Financial Position
Current assets		281,309					314,245
Total assets		4,870,201					4,867,546
Current liabilities		451,156					457,361
Owners’ equity – non-controlling interest		68,344					68,920
Public Service Company of New Mexico | Valencia
Variable Interest Entity [Line Items]
Payment for fixed costs		4,900	4,800
Payment for variable costs		$ 100	200
Long-term contract option to purchase, ownership percentage		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		$ 4,927	4,937
Operating expenses		(1,475)	(1,650)
Earnings attributable to non-controlling interest		3,452	$ 3,287
Financial Position
Current assets		2,841					2,551
Net property, plant, and equipment		66,237					66,947
Total assets		69,078					69,498
Current liabilities		734					578
Owners’ equity – non-controlling interest		$ 68,344					$ 68,920
Public Service Company of New Mexico | 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
Cash used to support bank letter or credit arrangement	30,300	$ 30,300
NM Capital | San Juan Coal Company, Westmoreland | Coal supply
Variable Interest Entity [Line Items]
Loan receivable	$ 125,000	85,400
Interest receivable		$ 1,400
NM Capital | San Juan Coal Company, Westmoreland | Coal supply | Subsequent event
Variable Interest Entity [Line Items]
Scheduled principal payment proceeds				$ 9,600	$ 9,600
Scheduled interest payment proceeds				$ 2,200	$ 2,200
Unaffiliated third party | San Juan Coal Company, Westmoreland | Coal supply | Subsequent event
Variable Interest Entity [Line Items]
Amount held in a restricted bank account						$ 11,800

XML

Lease Commitments (Details) - Public Service Company of New Mexico $ in Millions	Jan. 15, 2016 USD ($) lease MW	Mar. 31, 2017 USD ($) lease	Jan. 31, 2016 lease	Jan. 15, 2015 lease
Palo Verde Nuclear Generating Station, Unit 1 Leases
Operating Leased Assets [Line Items]
Number of leases, expiring				4
Number of leases under which lease term was extended				4
Palo Verde Nuclear Generating Station, Unit 2 Leases
Operating Leased Assets [Line Items]
Number of leases, expiring	4
Number of leases under which lease term was extended	1
Number of leases under which assets were purchased	3	3	3
Leased capacity to be purchased (in megawatts) | MW	32.8
Palo Verde Nuclear Generating Station, Unit 2 Leases, 31.25 MW
Operating Leased Assets [Line Items]
Number of leases under which assets were purchased	1
Payment to lessors | $	$ 78.1
Palo Verde Nuclear Generating Station, Unit 2 Leases, January 15, 2016
Operating Leased Assets [Line Items]
Leased capacity to be purchased (in megawatts) | MW	31.3
Palo Verde Nuclear Generating Station, Unit 2 Leases, 32.76 MW
Operating Leased Assets [Line Items]
Number of leases under which assets were purchased	2
Payment to lessors | $	$ 85.2
Palo Verde Nuclear Generating Station
Operating Leased Assets [Line Items]
Loss contingency, lease arrangements | $		$ 173.0

XML

Fair Value of Derivative and Other Financial Instruments - Overview and Commodity Derivatives (Details)	Mar. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)
Derivatives, Fair Value [Line Items]
Expected exposure to market risk (in megawatts) | MW	65
Current assets	$ 4,586,000	$ 5,224,000
Current liabilities	(360,000)	(2,339,000)
PNMR and PNM
Derivatives, Fair Value [Line Items]
Amounts recognized for the right to reclaim cash collateral	0	0
Amounts posted as cash collateral under margin arrangements	1,500,000	2,600,000
Obligations to return cash collateral	100,000	100,000
PNMR and PNM | Designated as Hedging Instrument | Commodity derivatives
Derivatives, Fair Value [Line Items]
Current assets	4,586,000	5,224,000
Current liabilities	(360,000)	(2,339,000)
Net	4,226,000	2,885,000
PNMR and PNM | Designated as Hedging Instrument | Commodity derivatives | Palo Verde Nuclear Generating Station
Derivatives, Fair Value [Line Items]
Current assets	2,000,000	2,700,000
PNM
Derivatives, Fair Value [Line Items]
Current assets	4,586,000	5,224,000
Current liabilities	(360,000)	(2,339,000)
PNM | Designated as Hedging Instrument | Commodity derivatives | Fuel and purchased power costs
Derivatives, Fair Value [Line Items]
Current assets	100,000	200,000
Current liabilities	$ (100,000)	$ (100,000)

XML

Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - Designated as Hedging Instrument - Commodity derivatives - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss)	$ 3,352	$ 2,539
Electric operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss)	3,341	2,684
Cost of energy
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss)	$ 11	$ (145)

XML

Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) - PNMR and PNM	3 Months Ended	12 Months Ended
	Mar. 31, 2017 USD ($) MMBTU MWh	Dec. 31, 2016 USD ($) MMBTU MWh
Derivative [Line Items]
Contractual liability	$ 0	$ 0
Posted cash collateral	0	0
Net exposure	$ 0	$ 0
Commodity derivatives | Fair value hedging | Buy
Derivative [Line Items]
Economic Hedges (in mmbtu and mwh) | MMBTU	100,000	254,100
Commodity derivatives | Fair value hedging | Sell
Derivative [Line Items]
Economic Hedges (in mmbtu and mwh) | MWh	1,834,125	2,471,600

XML

Fair Value of Derivative and Other Financial Instruments - Sale of Power (Details)	Dec. 31, 2017 $ / MWh	Mar. 31, 2017 MW
Palo Verde Nuclear Generating Station Unit 3 | PNMR and PNM
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Number of megawatts nuclear generation (in megawatts) | MW		134
Palo Verde Nuclear Generating Station Unit 3 | PNMR and PNM | Commodity derivatives | Subsequent event
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative, average forward price (in dollars per MWh) | $ / MWh	29
Palo Verde Nuclear Generating Station | PNM | Contract
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Percentage of electric power plant output sold		100.00%

XML

Fair Value of Derivative and Other Financial Instruments - Available for Sale Securities (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
(Increase)/decrease in other than temporary losses of available-for-sale securities, net portion recognized in earnings	$ 1,100,000	$ 1,600,000
Available-for-sale securities for which carrying value exceeds fair value	0
Held-to-maturity securities for which carrying value exceeds fair value	0
Impairments considered to be other than temporary	0
PNMR and PNM
Schedule of Available-for-sale Securities [Line Items]
Fair Value	286,099,000		$ 272,977,000
Unrealized Gains	12,406,000		7,449,000
Proceeds from sales	266,388,000	124,900,000
Gross realized gains	8,645,000	10,716,000
Gross realized (losses)	(3,085,000)	$ (6,116,000)
PNMR and PNM | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	286,099,000		272,977,000
PNMR and PNM | Nuclear Decommissioning Trust | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	266,100,000		253,900,000
PNMR and PNM | Mine Reclamation Trust | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	20,000,000		19,100,000
PNMR and PNM | Cash and cash equivalents
Schedule of Available-for-sale Securities [Line Items]
Fair Value	8,047,000		23,683,000
Unrealized Gains	0		0
PNMR and PNM | Cash and cash equivalents | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	8,047,000		23,683,000
PNMR and PNM | Domestic value
Schedule of Available-for-sale Securities [Line Items]
Fair Value	70,043,000		34,796,000
Unrealized Gains	3,044,000		1,135,000
PNMR and PNM | Domestic value | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	70,043,000		34,796,000
PNMR and PNM | Domestic growth
Schedule of Available-for-sale Securities [Line Items]
Fair Value	65,127,000		47,595,000
Unrealized Gains	4,438,000		3,032,000
PNMR and PNM | Domestic growth | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	65,127,000		47,595,000
PNMR and PNM | International and other
Schedule of Available-for-sale Securities [Line Items]
Fair Value	36,442,000		27,481,000
Unrealized Gains	3,555,000		2,029,000
PNMR and PNM | International and other | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	36,442,000		27,481,000
PNMR and PNM | U.S. Government
Schedule of Available-for-sale Securities [Line Items]
Fair Value	31,410,000		40,962,000
Unrealized Gains	178,000		115,000
PNMR and PNM | U.S. Government | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	31,410,000		40,962,000
PNMR and PNM | Municipals
Schedule of Available-for-sale Securities [Line Items]
Fair Value	33,218,000		43,789,000
Unrealized Gains	617,000		585,000
PNMR and PNM | Municipals | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	33,218,000		43,789,000
PNMR and PNM | Corporate and other
Schedule of Available-for-sale Securities [Line Items]
Fair Value	41,812,000		54,671,000
Unrealized Gains	574,000		553,000
PNMR and PNM | Corporate and other | Fair Value, Measurements, Recurring
Schedule of Available-for-sale Securities [Line Items]
Fair Value	$ 41,812,000		$ 54,671,000

XML

Fair Value of Derivative and Other Financial Instruments - Maturities of Debt Securities (Details) $ in Thousands	Mar. 31, 2017 USD ($)
PNMR and PNM
Available-for-Sale
Within 1 year	$ 3,852
After 1 year through 5 years	23,629
After 5 years through 10 years	29,024
After 10 years through 15 years	3,963
After 15 years through 20 years	8,728
After 20 years	37,244
Available-for-sale debt securities	106,440
PNMR
Held-to-Maturity
Within 1 year	0
After 1 year through 5 years	96,444
After 5 years through 10 years	0
Held-to-maturity debt securities	$ 96,444

XML

Fair Value of Derivative and Other Financial Instruments - Items Recorded and Presented by Level of Hierarchy (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
PNMR and PNM
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 286,099	$ 272,977
PNMR and PNM | Cash and cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	8,047	23,683
PNMR and PNM | Domestic value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	70,043	34,796
PNMR and PNM | Domestic growth
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	65,127	47,595
PNMR and PNM | International and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	36,442	27,481
PNMR and PNM | U.S. Government
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	31,410	40,962
PNMR and PNM | Municipals
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	33,218	43,789
PNMR and PNM | Corporate and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	41,812	54,671
PNMR
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,525,916	2,540,693
Westmoreland Loan	96,444
Westmoreland Loan		100,893
Other investments	1,051	1,164
PNMR | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Westmoreland Loan	0
Westmoreland Loan		0
Other investments	419	547
PNMR | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,525,916	2,540,693
Westmoreland Loan	0
Westmoreland Loan		0
Other investments	0	0
PNMR | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Westmoreland Loan	96,444
Westmoreland Loan		100,893
Other investments	632	617
PNMR | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,384,160	2,392,712
Westmoreland Loan	85,410
Westmoreland Loan		95,000
Other investments	419	547
PNM
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,728,276	1,730,157
Other investments	188	316
PNM | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	188	316
PNM | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,728,276	1,730,157
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	1,631,972	1,631,369
Other investments	188	316
TNMP
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	464,877	468,329
Other investments	231	231
TNMP | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	231	231
TNMP | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	464,877	468,329
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	420,950	420,875
Other investments	231	231
Fair Value, Measurements, Recurring | PNMR and PNM
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	286,099	272,977
Fair Value, Measurements, Recurring | PNMR and PNM | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	206,608	196,436
Fair Value, Measurements, Recurring | PNMR and PNM | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	79,491	76,541
Fair Value, Measurements, Recurring | PNMR and PNM | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	4,586	5,224
Commodity derivative liabilities	(360)	(2,339)
Net	4,226	2,885
Fair Value, Measurements, Recurring | PNMR and 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
Fair Value, Measurements, Recurring | PNMR and PNM | Commodity derivatives | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	4,586	5,224
Commodity derivative liabilities	(360)	(2,339)
Net	4,226	2,885
Fair Value, Measurements, Recurring | PNMR and PNM | Cash and cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	8,047	23,683
Fair Value, Measurements, Recurring | PNMR and PNM | Cash and cash equivalents | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	8,047	23,683
Fair Value, Measurements, Recurring | PNMR and PNM | Cash and cash equivalents | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring | PNMR and PNM | Domestic value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	70,043	34,796
Fair Value, Measurements, Recurring | PNMR and PNM | Domestic value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	70,043	34,796
Fair Value, Measurements, Recurring | PNMR and PNM | Domestic value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring | PNMR and PNM | Domestic growth
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	65,127	47,595
Fair Value, Measurements, Recurring | PNMR and PNM | Domestic growth | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	65,127	47,595
Fair Value, Measurements, Recurring | PNMR and PNM | Domestic growth | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring | PNMR and PNM | International and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	36,442	27,481
Fair Value, Measurements, Recurring | PNMR and PNM | International and other | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	33,212	27,481
Fair Value, Measurements, Recurring | PNMR and PNM | International and other | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,230	0
Fair Value, Measurements, Recurring | PNMR and PNM | U.S. Government
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	31,410	40,962
Fair Value, Measurements, Recurring | PNMR and PNM | U.S. Government | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	30,179	39,723
Fair Value, Measurements, Recurring | PNMR and PNM | U.S. Government | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,231	1,239
Fair Value, Measurements, Recurring | PNMR and PNM | Municipals
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	33,218	43,789
Fair Value, Measurements, Recurring | PNMR and PNM | Municipals | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring | PNMR and PNM | Municipals | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	33,218	43,789
Fair Value, Measurements, Recurring | PNMR and PNM | Corporate and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	41,812	54,671
Fair Value, Measurements, Recurring | PNMR and PNM | Corporate and other | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	23,158
Fair Value, Measurements, Recurring | PNMR and PNM | Corporate and other | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 41,812	$ 31,513

XML

Stock-Based Compensation (Details) - USD ($)		3 Months Ended		12 Months Ended
	Mar. 03, 2017	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Feb. 28, 2017	Mar. 31, 2015	Jan. 01, 2015	Mar. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)		0
Vesting period		1 year
Unrecognized expense related to stock awards		$ 6,900,000		$ 4,500,000
Excess tax benefits		$ 1,800,000
Cumulative effect adjustment (Note 8)				$ 10,382,000
Restricted Stock, Shares
Expired (in shares)		(3,000)
Restricted Stock, Weighted- Average Grant Date Fair Value
Expired (in dollars per share)		$ 30.50
Stock Options, Shares
Outstanding at beginning of period (in shares)		305,874
Granted (in shares)		0
Exercised (in shares)		(59,600)
Forfeited (in shares)		0
Expired (in shares)		(3,000)
Outstanding at end of period (in shares)		243,274		305,874
Stock Options, Weighted- Average Exercise Price
Outstanding at beginning of period (in dollars per share)		$ 12.29
Granted (in dollars per share)		0.00
Exercised (in dollars per share)		18.66
Forfeited (in dollars per share)		0.00
Expired (in dollars per share)		30.50
Outstanding at end of period (in dollars per share)		10.51		$ 12.29
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		945,000	$ 853,000
Chairman, President, and Chief Executive Officer | Common stock | Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 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)								135,000
Chairman, President, and Chief Executive Officer | Common stock | Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 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)					100,000			35,000
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
Executive Vice President and Chief Financial Officer | Common stock | Achieved performance target for 2015 and 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, purchase price of common stock							$ 100,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant					100,000
Restricted Stock, Shares
Granted (in shares)	2,754
Restricted Stock, Weighted- Average Grant Date Fair Value
Granted (in dollars per share)	$ 36.30
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value (in dollars per share)	$ 36.30
Executive Vice President and Chief Financial Officer | Common stock | Achieved performance target for 2015, 2016 and 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, purchase price of common stock							$ 275,000
Retained Earnings
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cumulative effect adjustment (Note 8)				$ 10,382,000
Accounting Standards Update 2016-09
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accumulated deferred income taxes				(8,400,000)
Accounting Standards Update 2016-09 | Retained Earnings
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cumulative effect adjustment (Note 8)				$ 10,400,000
PNM
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Excess tax benefits		1,300,000
TNMP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Excess tax benefits		$ 500,000
Restricted Shares and Performance Based Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period of time stock expense is expected to be recognized		2 years 4 months 24 days		1 year 9 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)		$ 0.2425	$ 0.2200
Risk-free interest rate		1.58%	1.00%
Restricted Stock
Restricted Stock, Shares
Outstanding at beginning of period (in shares)		218,316
Granted (in shares)		231,107
Exercised (in shares)		(248,003)
Forfeited (in shares)		(822)
Expired (in shares)		0
Outstanding at end of period (in shares)		200,598		218,316
Restricted Stock, Weighted- Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)		$ 27.59
Granted (in dollars per share)		22.12	$ 26.05
Exercised (in dollars per share)		20.26
Forfeited (in dollars per share)		27.86
Expired (in dollars per share)		0.00
Outstanding at end of period (in dollars per share)		$ 30.35		$ 27.59
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)		$ 22.12	$ 26.05
Total fair value of restricted shares that vested		$ 5,024,000	$ 4,131,000
Performance Shares | Executive
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		49,682
Shares exercised (in shares)		49,682
Weighted percentage assigned to achieving market targets		60.00%
Weighted percentage assigned to achieving performance targets		40.00%
Maximum number of shares awarded in year 1 (in shares)		163,712
Maximum number of shares awarded in year 2 (in shares)		137,036
Maximum number of shares awarded in year 3 (in shares)		133,632
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		1.54%	0.97%
Dividend yield		2.67%	2.74%
Expected volatility		20.80%	20.44%
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of stock options outstanding		$ 6,400,000
Weighted-average remaining contract life		2 years 1 month 6 days
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%

XML

Financing - Financing Activities (Details) - USD ($)			1 Months Ended	3 Months Ended	12 Months Ended
	Mar. 09, 2017	Feb. 01, 2016	Mar. 31, 2017	Mar. 31, 2017	Dec. 31, 2016	Oct. 21, 2016	Sep. 30, 2015	Mar. 09, 2015
Debt Instrument [Line Items]
Fixed interest rate							1.927%
Estimated principal payments			$ 283,500,000	$ 283,500,000
PNMR 2015 Term Loan Agreement
Debt Instrument [Line Items]
Interest rate at period end			1.75%	1.75%
PNMR 2016 Two-Year Term Loan
Debt Instrument [Line Items]
Term loans			$ 100,000,000.0	$ 100,000,000.0
Interest rate			1.93%	1.93%
Variable rate short-term debt
Debt Instrument [Line Items]
Fixed interest rate	1.926%
Aggregate principal amount	$ 50,000,000.0
Term of hedging agreement	4 years
Cash flow hedge | Level 2
Debt Instrument [Line Items]
Fair value gain (loss)			$ (400,000)	$ 200,000	$ (100,000)
PNM
Debt Instrument [Line Items]
Estimated principal payments			232,000,000	$ 232,000,000
PNM | Maximum
Debt Instrument [Line Items]
Maturity term over which financings require regulator approval (more than)				18 months
NM Capital | Coal supply | San Juan Coal Company, Westmoreland
Debt Instrument [Line Items]
Payments to fund long-term loans to unaffiliated third party		$ 125,000,000.0
Line of credit
Debt Instrument [Line Items]
Ratio of debt to capital (less than or equal to)				65.00%
PNMR 2015 Term Loan Agreement
Debt Instrument [Line Items]
Term loans								$ 150,000,000.0
PNM 2016 Term Loan Agreement [Member] | PNM
Debt Instrument [Line Items]
Aggregate principal amount			$ 175,000,000.0	$ 175,000,000.0
Interest rate			1.59%	1.59%
BTMU Term Loan Agreement | NM Capital
Debt Instrument [Line Items]
Term loans		$ 125,000,000.0	$ 82,800,000	$ 82,800,000
Stated interest rate			3.79%	3.79%
Estimated principal payments			$ 33,500,000	$ 33,500,000
Letter of credit | PNMR | JPM LOC Facility
Debt Instrument [Line Items]
Aggregate principal amount						$ 30,300,000.0

XML

Financing - Short-term Debt and Liquidity (Details) - USD ($)	Nov. 01, 2020	Apr. 24, 2017	Mar. 31, 2017	Dec. 31, 2016	Nov. 30, 2016
Short-term Debt [Line Items]
Short-term debt			$ 303,100,000	$ 287,100,000
Letters of credit outstanding			6,200,000
Maturities and other repayments due in next 12 months			283,500,000
Maturities and other repayments due in the remainder of year two			$ 106,800,000
Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity		$ 605,300,000
PNMR 2016 One-Year Term Loan
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt			1.83%
Short-term debt			$ 100,000,000	100,000,000
PNMR Revolving Credit Facility
Short-term Debt [Line Items]
Financing capacity					$ 10,000,000.0
PNMR Revolving Credit Facility | Forecast
Short-term Debt [Line Items]
Financing capacity	$ 290,000,000.0
PNMR | Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity		137,700,000
Consolidated invested cash		1,500,000
PNMR | PNMR Revolving Credit Facility
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt			2.19%
PNMR | Revolving credit facility
Short-term Debt [Line Items]
Financing capacity			$ 300,000,000.0
Short-term debt			164,900,000	126,100,000
Public Service Company of New Mexico
Short-term Debt [Line Items]
Short-term debt			16,200,000	61,000,000
Letters of credit outstanding			2,500,000
Maturities and other repayments due in next 12 months			232,000,000
Maturities and other repayments due in the remainder of year two			450,000,000
Public Service Company of New Mexico | Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity		389,700,000
Consolidated invested cash		0
Public Service Company of New Mexico | Lines of credit
Short-term Debt [Line Items]
NMPRC approved credit facility			50,000,000
Short-term debt			0	26,000,000
Maturities and other repayments due			$ 50,000,000
Public Service Company of New Mexico | Lines of credit | Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity		43,000,000
Public Service Company of New Mexico | PNM Revolving Credit Facility
Short-term Debt [Line Items]
Financing capacity					$ 40,000,000.0
Weighted-average interest rate for short-term debt			2.11%
Public Service Company of New Mexico | PNM Revolving Credit Facility | Forecast
Short-term Debt [Line Items]
Financing capacity	$ 360,000,000.0
Public Service Company of New Mexico | Revolving credit facility
Short-term Debt [Line Items]
Financing capacity			$ 400,000,000.0
Short-term debt			16,200,000	35,000,000
TNMP
Short-term Debt [Line Items]
Short-term debt			22,000,000	0
Letters of credit outstanding			100,000
Intercompany borrowings			6,300,000
Short-term debt – affiliate			6,300,000	4,600,000
Maturities and other repayments due			$ 0
TNMP | Subsequent event
Short-term Debt [Line Items]
Remaining borrowing capacity		34,900,000
Consolidated invested cash		0
TNMP | Subsequent event | Affiliated entity
Short-term Debt [Line Items]
Short-term debt – affiliate		$ 5,000,000
TNMP | PNM Revolving Credit Facility
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt			1.94%
TNMP | Revolving credit facility
Short-term Debt [Line Items]
Financing capacity			$ 75,000,000.0
Short-term debt			22,000,000	$ 0
Maturities and other repayments due in 2018			75,000,000
TNMP | Revolving credit facility | First mortgage bonds
Short-term Debt [Line Items]
Collateral amount			$ 75,000,000

XML

Pension and Other Postretirement Benefit Plans (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Public Service Company of New Mexico | Pension Plan
Components of Net Periodic Benefit Cost
Service cost	$ 0	$ 0
Interest cost	6,727,000	7,577,000
Expected return on plan assets	(8,451,000)	(8,854,000)
Amortization of net (gain) loss	4,001,000	3,455,000
Amortization of prior service cost	(241,000)	(241,000)
Net Periodic Benefit Cost (Income)	2,036,000	1,937,000
Contributions by employer	0	0
Total expected employer contributions for future fiscal years	$ 0
Public Service Company of New Mexico | Pension Plan | Minimum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate	4.10%
Public Service Company of New Mexico | Pension Plan | Maximum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate	4.90%
Public Service Company of New Mexico | OPEB Plan
Components of Net Periodic Benefit Cost
Service cost	$ 24,000	35,000
Interest cost	1,006,000	1,087,000
Expected return on plan assets	(1,308,000)	(1,371,000)
Amortization of net (gain) loss	921,000	286,000
Amortization of prior service cost	(416,000)	(7,000)
Net Periodic Benefit Cost (Income)	227,000	30,000
Contributions by employer	0	800,000
Total expected employer contributions for future fiscal years	0
Public Service Company of New Mexico | Executive Retirement Program
Components of Net Periodic Benefit Cost
Service cost	0	0
Interest cost	174,000	203,000
Expected return on plan assets	0	0
Amortization of net (gain) loss	78,000	64,000
Amortization of prior service cost	0	0
Net Periodic Benefit Cost (Income)	252,000	267,000
Contributions by employer	500,000	500,000
Total expected employer contributions for future fiscal years	5,800,000
Total expected employer contributions for fiscal year	1,500,000
Texas-New Mexico Power Company | Pension Plan
Components of Net Periodic Benefit Cost
Service cost	0	0
Interest cost	722,000	826,000
Expected return on plan assets	(945,000)	(986,000)
Amortization of net (gain) loss	231,000	175,000
Amortization of prior service cost	0	0
Net Periodic Benefit Cost (Income)	8,000	15,000
Contributions by employer	0	0
Total expected employer contributions for future fiscal years	$ 0
Texas-New Mexico Power Company | Pension Plan | Minimum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate	4.10%
Texas-New Mexico Power Company | Pension Plan | Maximum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate	4.90%
Texas-New Mexico Power Company | OPEB Plan
Components of Net Periodic Benefit Cost
Service cost	$ 36,000	46,000
Interest cost	139,000	169,000
Expected return on plan assets	(114,000)	(122,000)
Amortization of net (gain) loss	(20,000)	(10,000)
Amortization of prior service cost	0	0
Net Periodic Benefit Cost (Income)	41,000	83,000
Contributions by employer	700,000	0
Total expected employer contributions for future fiscal years	1,400,000
Total expected employer contributions for fiscal year	0
Texas-New Mexico Power Company | Executive Retirement Program
Components of Net Periodic Benefit Cost
Service cost	0	0
Interest cost	8,000	10,000
Expected return on plan assets	0	0
Amortization of net (gain) loss	2,000	1,000
Amortization of prior service cost	0	0
Net Periodic Benefit Cost (Income)	10,000	$ 11,000
Total expected employer contributions for future fiscal years	400,000
Total expected employer contributions for fiscal year	100,000
Texas-New Mexico Power Company | Executive Retirement Program | Maximum
Components of Net Periodic Benefit Cost
Contributions by employer	$ 100,000.0

XML

Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - Public Service Company of New Mexico - Nuclear spent fuel and waste disposal - Palo Verde Nuclear Generating Station - USD ($)	May 16, 2014	Mar. 31, 2017	Dec. 31, 2016
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss		$ 57,700,000
Revised annual fee, nuclear waste disposal	$ 0
Other deferred credits
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual		$ 12,000,000	$ 12,100,000

XML

Commitments and Contingencies - The Clean Air Act (Details)					3 Months Ended			6 Months Ended	12 Months Ended		49 Months Ended
	Feb. 25, 2016	Dec. 16, 2015 USD ($) MWh MW	Jul. 31, 2015 USD ($) MW	Mar. 02, 2015 lb / MMBTU T	Mar. 31, 2017 USD ($) lbsofnox / mmbtu joint_owner requirement well MW	Dec. 31, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Mar. 31, 2017 USD ($) lbsofnox / mmbtu joint_owner requirement well MW	Dec. 31, 2017 portfolio	Jan. 26, 2016 state	Oct. 01, 2015 parts_per_billion	Sep. 30, 2015 parts_per_billion	May 14, 2015 lb / MMBTU	Dec. 30, 2013	Feb. 28, 2013 lawsuit state mine	Aug. 06, 2012 compliance_alternative	Jan. 31, 2010 parts_per_billion	Jul. 31, 2005 T	Dec. 31, 1999 state
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs					$ 0		$ 774,000
Plant in service, held for future use, and to be abandoned					7,009,698,000	$ 6,944,534,000		$ 6,944,534,000	$ 6,944,534,000		$ 7,009,698,000
Accumulated depreciation and amortization					2,373,542,000	2,334,938,000		2,334,938,000	2,334,938,000		2,373,542,000
Public Service Company of New Mexico
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs					0		774,000
Plant in service, held for future use, and to be abandoned					5,383,068,000	5,359,211,000		5,359,211,000	5,359,211,000		5,383,068,000
Accumulated depreciation and amortization					$ 1,832,695,000	1,809,528,000		1,809,528,000	1,809,528,000		$ 1,832,695,000
Public Service Company of New Mexico | Reeves Station
Public Utilities, Commitments And Contingencies [Line Items]
Requirements to be implemented | requirement					0						0
Public Service Company of New Mexico | Forecast
Public Utilities, Commitments And Contingencies [Line Items]
Number of resource portfolios | portfolio												2
Public Service Company of New Mexico | San Juan Generating Station Units 2 and 3
Public Utilities, Commitments And Contingencies [Line Items]
Plant in service, held for future use, and to be abandoned					$ 471,800,000						$ 471,800,000
Accumulated depreciation and amortization					206,400,000						206,400,000
Net book value					265,400,000						265,400,000
Public Service Company of New Mexico | San Juan Generating Station | Loss on long-term purchase commitment | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs										$ 16,500,000
Estimate of possible loss					$ 102,000,000						$ 102,000,000
Public Service Company of New Mexico | San Juan Generating Station | Forecast
Public Utilities, Commitments And Contingencies [Line Items]
Number of portfolios for continuing operations | portfolio												1
Number of portfolios with discontinued operations | portfolio												1
Public Service Company of New Mexico | San Juan Generating Station and Four Corners | Maximum
Public Utilities, Commitments And Contingencies [Line Items]
Proposed government standard emission limit (in ozone parts per million) | parts_per_billion																				70
Government standard emission limit (in ozone parts per million) | parts_per_billion														70	75
Public Service Company of New Mexico | San Juan Generating Station and Four Corners | Minimum
Public Utilities, Commitments And Contingencies [Line Items]
Proposed government standard emission limit (in ozone parts per million) | parts_per_billion																				60
PNMR and PNM | Palo Verde Nuclear Generating Station Unit 3
Public Utilities, Commitments And Contingencies [Line Items]
Number of megawatts | MW					134						134
PNMR Development | Energy equipment
Public Utilities, Commitments And Contingencies [Line Items]
Costs of installing equipment			$ 7,600,000
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 Air Act, SNCR | San Juan Generating Station Unit 4
Public Utilities, Commitments And Contingencies [Line Items]
Number of other joint owners | joint_owner					8						8
Clean Air Act, SNCR | Public Service Company of New Mexico
Public Utilities, Commitments And Contingencies [Line Items]
Estimated costs to remain unrecovered		$ 20,000,000
Clean Air Act, SNCR | Public Service Company of New Mexico | San Juan Generating Station Units 1 and 4 | Plan
Public Utilities, Commitments And Contingencies [Line Items]
Ownership percentage			66.30%
Clean Air Act, SNCR | Public Service Company of New Mexico | San Juan Generating Station Units 1 and 4 | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other Costs
Public Utilities, Commitments And Contingencies [Line Items]
Total costs for equipment											$ 77,900,000
Clean Air Act, SNCR | Public Service Company of New Mexico | San Juan Generating Station Units 2 and 3
Public Utilities, Commitments And Contingencies [Line Items]
Current ownership interest (in megawatts) | MW		418
Time period to recover retired units' remaining net book value		20 years
Recovery percentage of estimated undepreciated value at 12/31/17		50.00%			50.00%					50.00%	50.00%
Regulatory disallowances and restructuring costs										$ 127,600,000
Expense reflected in regulatory disallowances and restructuring costs							$ 800,000		3,700,000
Accumulated plant write-off, disallowance					$ 128,600,000						$ 128,600,000
Net carrying value of utility plant					$ 136,800,000						$ 136,800,000
Clean Air Act, SNCR | Public Service Company of New Mexico | San Juan Generating Station Units 2 and 3 | Increase in coal mine decommissioning liability
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs										$ 165,700,000
Clean Air Act, SNCR | Public Service Company of New Mexico | San Juan Generating Station Unit 4
Public Utilities, Commitments And Contingencies [Line Items]
Additional ownership to be obtained (in megawatts) | MW		65	132
Estimated rate base value		$ 0
Coal-fired generation (in megawatts) | MW		197
Number of megawatt hours of Renewable Energy Certificates to be acquired and retired (in megawatt hours) | MWh		1
Percentage of ownership held by exiting owners					38.80%						38.80%
Ownership percentage					38.50%						38.50%
Clean Air Act, SNCR | Public Service Company of New Mexico | San Juan Generating Station Unit 4 | Maximum
Public Utilities, Commitments And Contingencies [Line Items]
Annual cost of Renewable Energy Credits		$ 7,000,000
Clean Air Act, SNCR | Public Service Company of New Mexico | San Juan Generating Station Unit 4 | Plan
Public Utilities, Commitments And Contingencies [Line Items]
Ownership percentage			77.30%
Clean Air Act, SNCR | Public Service Company of New Mexico | Palo Verde Nuclear Generating Station Unit 3
Public Utilities, Commitments And Contingencies [Line Items]
Estimated undepreciated value at 12/31/17		$ 156,000,000
Clean Air Act, SNCR | Public Service Company of New Mexico | San Juan Generating Station Unit 3
Public Utilities, Commitments And Contingencies [Line Items]
Percentage of ownership held by exiting owners					50.00%						50.00%
Ownership percentage					50.00%						50.00%
Clean Air Act, SNCR | PNMR and PNM | Palo Verde Nuclear Generating Station Unit 3
Public Utilities, Commitments And Contingencies [Line Items]
Number of megawatts | MW		134
Clean Air Act, SNCR | PNMR Development | San Juan Generating Station Unit 4
Public Utilities, Commitments And Contingencies [Line Items]
Additional ownership to be obtained (in megawatts) | MW			65
Expense for cost, obligation to reimburse						$ 600,000
Potential acquisition of ownership (in megawatts) | MW			65
Clean Air Act, SNCR Hearing Examiner, Recommended Denial | Public Service Company of New Mexico | San Juan Generating Station Unit 4
Public Utilities, Commitments And Contingencies [Line Items]
Additional ownership to be obtained (in megawatts) | MW		132
Clean Air Act, Post-2022 coal supply future rate case | Public Service Company of New Mexico | San Juan Generating Station Unit 4
Public Utilities, Commitments And Contingencies [Line Items]
Period of time agreed to by all parties to settle rate case		6 months
Increase in coal mine decommissioning liability | Public Service Company of New Mexico
Public Utilities, Commitments And Contingencies [Line Items]
Expense reflected in regulatory disallowances and restructuring costs								$ 4,500,000	$ 4,500,000
Clean Air Act related to post combustion controls | Public Service Company of New Mexico | Four Corners
Public Utilities, Commitments And Contingencies [Line Items]
Number of compliance alternatives | compliance_alternative																			2
Plant requirement to meet NOx emissions limit (in pounds of NOx per MMBTU) | lbsofnox / mmbtu					0.015						0.015
Plant requirement to meet opacity limit					20.00%						20.00%
Rule imposes opacity limitation on certain fugitive dust emissions from coal and material handling operations					20.00%						20.00%
Estimate of possible loss					$ 90,200,000						$ 90,200,000
Clean Air Act related to post combustion controls | Public Service Company of New Mexico | Four Corners Units 4 and 5 (Coal)
Public Utilities, Commitments And Contingencies [Line Items]
Ownership percentage					13.00%						13.00%
Clean Air Act related to post combustion controls | Public Service Company of New Mexico | Four Corners Units 1, 2 and 3 (Coal)
Public Utilities, Commitments And Contingencies [Line Items]
Ownership percentage																	0.00%
Clean Power Plan
Public Utilities, Commitments And Contingencies [Line Items]
Period of potential extension to meet environmental targets					2 years
Number of states that filed a petition against the Clean Power Plan | state													29
National Ambient Air Quality Standards, 2015 EPA Legal Settlement | Public Service Company of New Mexico
Public Utilities, Commitments And Contingencies [Line Items]
Period of time to act on settlement				16 months
Emissions tons of SO2 per year (more than) | T				16,000
National Ambient Air Quality Standards, 2015 EPA Legal Settlement | Public Service Company of New Mexico | Minimum
Public Utilities, Commitments And Contingencies [Line Items]
Emissions tons of SO2 per year (more than) | T				2,600
One-hour SO2 emissions rate (in pounds per MMBTU) | lb / MMBTU				0.45
National Ambient Air Quality Standards | Public Service Company of New Mexico | San Juan Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Revised SO2 emissions (in pounds per MMBTU) | lb / MMBTU																0.10
National Ambient Air Quality Standards, 2015 EPA Legal Settlement | Public Service Company of New Mexico
Public Utilities, Commitments And Contingencies [Line Items]
Period of time from state designation, to provide implementation plans	36 months
WEG v OSM lawsuit | Public Service Company of New Mexico
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 (in lawsuits) | lawsuit																		15
WEG v OSM lawsuit | Public Service Company of New Mexico | San Juan Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Number of claims for relief, filed (in lawsuits) | lawsuit																		2
Santa Fe generating station | Public Service Company of New Mexico
Public Utilities, Commitments And Contingencies [Line Items]
Number of wells with elevated levels of nitrates | well					3						3

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Commitments and Contingencies - Coal Supply (Details)			3 Months Ended		6 Months Ended	12 Months Ended
	Feb. 01, 2016 USD ($)	Jan. 31, 2016 USD ($)	Mar. 31, 2017 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	May 02, 2017 USD ($)	May 01, 2017 USD ($)	Apr. 24, 2017 USD ($)	Feb. 01, 2017	Aug. 01, 2016 payment
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets			$ 66,093,000		$ 73,444,000	$ 73,444,000
Regulatory disallowances and restructuring costs			0	$ 774,000
Public Service Company of New Mexico
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets			60,425,000		67,355,000	67,355,000
Regulatory disallowances and restructuring costs			0	$ 774,000
Public Service Company of New Mexico | Increase in coal mine decommissioning liability
Public Utilities, Commitments And Contingencies [Line Items]
Expense reflected in regulatory disallowances and restructuring costs					4,500,000	4,500,000
Public Service Company of New Mexico | Mine Reclamation Trust
Public Utilities, Commitments And Contingencies [Line Items]
Required contribution to Reclamation Trust, current fiscal year			6,900,000
Anticipated funding to Reclamation Trust, next fiscal year			8,300,000
Anticipated funding to Reclamation Trust, third fiscal year			8,700,000
Public Service Company of New Mexico | Mine Reclamation Trust | Four Corners
Public Utilities, Commitments And Contingencies [Line Items]
Required contribution to Reclamation Trust, current fiscal year			2,000,000
Anticipated funding to Reclamation Trust, next fiscal year			2,100,000
Anticipated funding to Reclamation Trust, third fiscal year			2,100,000
Number of annual installment payments | payment												13
Public Service Company of New Mexico | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory assets			100,000,000
Public Service Company of New Mexico | Loss on long-term purchase commitment | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual			41,500,000		41,000,000	41,000,000
Final reclamation, capped amount to be collected			100,000,000.0
Public Service Company of New Mexico | Loss on long-term purchase commitment | Underground
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual			14,000,000		14,000,000	14,000,000
Public Service Company of New Mexico | San Juan Generating Station | Loss on long-term purchase commitment | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs							$ 16,500,000
Estimate of possible loss			102,000,000
Public Service Company of New Mexico | San Juan Generating Station | Loss on long-term purchase commitment | Underground
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss			127,800,000
Public Service Company of New Mexico | San Juan Generating Station | Coal supply
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets			43,000,000		$ 48,700,000	$ 48,700,000
Estimated increase in coal cost					48.00%	48.00%
NM Capital | BTMU Term Loan Agreement
Public Utilities, Commitments And Contingencies [Line Items]
Term loans	$ 125,000,000.0		82,800,000
NM Capital | San Juan Generating Station | Coal supply
Public Utilities, Commitments And Contingencies [Line Items]
Payments to fund long-term loans to unaffiliated third party		$ 125,000,000.0
Loan agreement among several entities		$ 125,000,000
Interest rate		7.25%									9.25%
Requirement to post reclamation bonds			118,700,000
Cash used to support bank letter or credit arrangement		$ 30,300,000	30,300,000
NM Capital | San Juan Coal Company, Westmoreland | Coal supply
Public Utilities, Commitments And Contingencies [Line Items]
Payments to fund long-term loans to unaffiliated third party	$ 125,000,000.0
Loan receivable		$ 125,000,000	85,400,000
Prepayment penalty			$ 0
NM Capital | San Juan Coal Company, Westmoreland | Coal supply | Subsequent event
Public Utilities, Commitments And Contingencies [Line Items]
Scheduled principal payment proceeds								$ 9,600,000	$ 9,600,000
Scheduled interest payment proceeds								$ 2,200,000	$ 2,200,000
Unaffiliated third party | San Juan Coal Company, Westmoreland | Coal supply | Subsequent event
Public Utilities, Commitments And Contingencies [Line Items]
Amount held in a restricted bank account										$ 11,800,000

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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	Apr. 30, 2010 city	Mar. 31, 2017 USD ($) generating_unit	Dec. 01, 2015 Allotment_Parcel	Jul. 13, 2015 a	Jan. 22, 2015 Allotment_Parcel	Apr. 02, 2014 landowner Allotment_Parcel	Feb. 27, 2014 lawsuit	Jan. 06, 2014 Allotment_Parcel	Aug. 31, 2013	Sep. 30, 2012 landowner
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
Palo Verde Nuclear Generating Station | Public Service Company of New Mexico
Public Utilities, Commitments And Contingencies [Line Items]
Number of cities to provide cooling water | city		5
Term of agreement for cooling water		40 years
Palo Verde Nuclear Generating Station | Public Service Company of New Mexico | 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			$ 38,900,000.0
Annual payment limitation related to incident			5,800,000.0
Aggregate amount of all risk insurance			2,750,000,000.00
Maximum amount under Nuclear Electric Insurance Limited			5,400,000.0
Palo Verde Nuclear Generating Station | Public Service Company of New Mexico | Nuclear plant | Commercial providers
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage			450,000,000
Palo Verde Nuclear Generating Station | Public Service Company of New Mexico | Nuclear plant | Industry Wide Retrospective Assessment Program
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage			13,000,000,000.0
Palo Verde Nuclear Generating Station | Public Service Company of New Mexico | Nuclear plant | Maximum
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage			13,400,000,000.0
Liability insurance coverage sublimit			$ 2,250,000,000.00
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%
Navajo Nation Allottee Matters | Public Service Company of New Mexico
Public Utilities, Commitments And Contingencies [Line Items]
Number of landowners claiming to be Navajo allottees (in landowners) | landowner							43				43
Number of allotment parcels' appraisal requested for review (in allotment parcels) | Allotment_Parcel									58
Number of allotments where landowners are revoking rights of way renewal consents (in allotment parcels) | Allotment_Parcel						10	6
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

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Regulatory and Rate Matters - PNM (Details) $ in Millions																	1 Months Ended	3 Months Ended		12 Months Ended			49 Months Ended
	Apr. 14, 2017 USD ($) GWh program	Mar. 27, 2017	Feb. 28, 2017 USD ($)	Jan. 11, 2017 USD ($)	Dec. 07, 2016 USD ($)	Nov. 30, 2016	Sep. 28, 2016 USD ($) MW	Aug. 04, 2016 USD ($) MW	Jun. 01, 2016 MW	May 04, 2016	Apr. 15, 2016 USD ($) GWh program	Jan. 15, 2016 USD ($) lease MW	Nov. 30, 2015	Aug. 27, 2015 USD ($)	Jan. 15, 2015	Jul. 01, 2014	Sep. 30, 2016 USD ($)	Mar. 31, 2017 USD ($) MWh lease MW	Mar. 31, 2016 USD ($)	Dec. 31, 2017 portfolio	Dec. 31, 2016 USD ($) MWh	Dec. 31, 2015 MW	Mar. 31, 2017 USD ($) lease MW	Oct. 26, 2016 MW	Jul. 08, 2016 service_rate MW	Apr. 26, 2016 MW	Feb. 26, 2016 USD ($)	Jan. 31, 2016 lease MW
Public Utilities, General Disclosures [Line Items]
Excess return on jurisdictional equity that would require refund																		0.50%					0.50%
Application filed for new electric service rates | service_rate																									2
NMPRC
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease)					$ 99.2
Requested return on equity					10.125%
Unopposed motion filed for extension of procedural schedule		1 month
Proposed revision to rider that will allow for recovery			$ 42.7
Action plan, covered period																		4 years
Public Service Company of New Mexico | Tri-State
Public Utilities, General Disclosures [Line Items]
Term of hazard sharing agreement									1 year
Each party will sell the other party capacity (in megawatts) | MW									100
Number of megawatt hours sold | MWh																		213,533			482,342
Megawatt hours sold																		$ 4.8			$ 12.8
Number of megawatt hours purchased | MWh																		205,156			484,632
Megawatt hours purchased																		$ 4.6			$ 12.9
Public Service Company of New Mexico | Forecast
Public Utilities, General Disclosures [Line Items]
Planning period covered of IRP																				20 years
Action plan, covered period																				4 years
Number of resource portfolios | portfolio																				2
Public Service Company of New Mexico | NMPRC
Public Utilities, General Disclosures [Line Items]
Action plan, covered period																4 years
Notice of Proposed Dismissal, period to show good cause										30 days
Public Service Company of New Mexico | NMPRC | Tri-State
Public Utilities, General Disclosures [Line Items]
Term of hazard sharing agreement						5 years												5 years
Public Service Company of New Mexico | San Juan Generating Station Units 1 and 4 | Clean Air Act, Balanced Draft Technology
Public Utilities, General Disclosures [Line Items]
Net book value																		$ 50.0					$ 50.0
Public Service Company of New Mexico | San Juan Generating Station Units 1 and 4 | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other Costs | Clean Air Act, Balanced Draft Technology
Public Utilities, General Disclosures [Line Items]
Installation costs								$ 52.3
Public Service Company of New Mexico | San Juan Generating Station Units 1 and 4 | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other Costs | Clean Air Act, SNCR
Public Utilities, General Disclosures [Line Items]
Installation costs																							77.9
Public Service Company of New Mexico | San Juan Generating Station | Forecast
Public Utilities, General Disclosures [Line Items]
Number of portfolios for continuing operations | portfolio																				1
Number of portfolios with discontinued operations | portfolio																				1
Public Service Company of New Mexico | San Juan Generating Station Units 2 and 3
Public Utilities, General Disclosures [Line Items]
Net book value																		$ 265.4					$ 265.4
Public Service Company of New Mexico | San Juan Generating Station Units 2 and 3 | Clean Air Act, SNCR
Public Utilities, General Disclosures [Line Items]
Newly identified replacement gas-fired generation (in megawatts) | MW																										80
Replacement gas-fired aeroderivative generation (in megawatts) | MW																										40
Public Service Company of New Mexico | Palo Verde Nuclear Generating Station, Unit 2 Leases
Public Utilities, General Disclosures [Line Items]
Number of megawatts purchased (in megawatts) | MW												64.1						64.1					64.1					64.1
Number of leases under which assets were purchased | lease												3						3					3					3
Estimated annual property tax expense												$ 0.8
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																		$ 76.9					$ 76.9
Net book value of capitalized improvements																		39.9					39.9
Public Service Company of New Mexico | Palo Verde Nuclear Generating Station, Unit 1 Leases, extended
Public Utilities, General Disclosures [Line Items]
Estimated annual property tax expense												$ 1.5
Estimated annual rent expense								$ 18.1
Number of leases under which lease term was extended | lease												4
Lease term extension period															8 years
Public Service Company of New Mexico | 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease)														$ 123.5
Requested rate increase (decrease) of non-fuel revenue								121.5						$ 121.7				121.5
Requested return on equity														10.50%
Requested rate increase (decrease) for fuel related costs																		(42.9)
Requested rate increase (decrease) for non-fuel related revenues																		(0.2)
Hearing examiner's recommended rate increase (decrease) of non-fuel revenue								$ 41.3
Hearing examiner's recommended return on equity								9.575%
Approved rate increase (decrease)							$ 61.2
Estimated period of time for supreme court appeal decision																	15 months
Approved recovery of net operating loss carryforward																	$ 2.1
Estimate of possible loss																		$ 154.9					$ 154.9
Public Service Company of New Mexico | 2015 Electric Rate Case | San Juan Generating Station Units 1 and 4 | Clean Air Act, Balanced Draft Technology
Public Utilities, General Disclosures [Line Items]
Requested base rate increase (decrease)								$ 40.0
Public Service Company of New Mexico | 2015 Electric Rate Case | San Juan Generating Station | Refined coal
Public Utilities, General Disclosures [Line Items]
Hearing examiner's recommended percentage of revenue to be credited to customers								100.00%
Public Service Company of New Mexico | 2015 Electric Rate Case | Palo Verde Nuclear Generating Station, Unit 2 Leases
Public Utilities, General Disclosures [Line Items]
Hearing examiner's proposed disallowance of recovery								$ 163.3
Initial rate base value							83.7
Disallowance of the recovery underpreciated costs of capitalized leasehold improvements							43.8
Period of time for which capital improvements were disallowed																	15 months
Pre-tax regulatory disallowance																	$ 6.8
Public Service Company of New Mexico | 2015 Electric Rate Case | Palo Verde Nuclear Generating Station, Unit 1 Leases, extended
Public Utilities, General Disclosures [Line Items]
Recovery of assumed operating and maintenance expense savings annually							$ 0.3
Public Service Company of New Mexico | 2015 Electric Rate Case | Alvarado square
Public Utilities, General Disclosures [Line Items]
Hearing examiner's recommended amount to not be recovered from retail customers								$ 4.5
Pre-tax regulatory disallowance of costs recorded as regulatory assets and deferred charges																	$ 4.5
Public Service Company of New Mexico | 2014 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Period of time after the filing of a rate case application													13 months
Public Service Company of New Mexico | Renewable Portfolio Standard
Public Utilities, General Disclosures [Line Items]
Number of megawatts of Solar PV facilities | MW																		107				40	107
Current output in the geothermal facility (in megawatts) | MW																		4					4
Solar generation capacity (in megawatts) | MW																		66.8					66.8
Public Service Company of New Mexico | Renewable Portfolio Standard | Minimum
Public Utilities, General Disclosures [Line Items]
Profit incentive sliding scale multiplier				7.10%
Public Service Company of New Mexico | Renewable Portfolio Standard | Maximum
Public Utilities, General Disclosures [Line Items]
Reasonable cost threshold				3.00%														3.00%					3.00%
Profit incentive sliding scale multiplier				9.00%
Public Service Company of New Mexico | Renewable Portfolio Standard | Wind | Minimum
Public Utilities, General Disclosures [Line Items]
Required percentage of diversification																		30.00%					30.00%
Public Service Company of New Mexico | Renewable Portfolio Standard | Solar | Minimum
Public Utilities, General Disclosures [Line Items]
Required percentage of diversification																		20.00%					20.00%
Public Service Company of New Mexico | Renewable Portfolio Standard | Distributed generation | Minimum
Public Utilities, General Disclosures [Line Items]
Required percentage of diversification																		3.00%					3.00%
Public Service Company of New Mexico | Renewable Portfolio Standard | Other | Minimum
Public Utilities, General Disclosures [Line Items]
Required percentage of diversification																		5.00%					5.00%
Public Service Company of New Mexico | Renewable Portfolio Standard | Required Percentage by 2011
Public Utilities, General Disclosures [Line Items]
Required percentage of renewable energy in portfolio to electric sales																		10.00%					10.00%
Public Service Company of New Mexico | Renewable Portfolio Standard | Required Percentage by 2015
Public Utilities, General Disclosures [Line Items]
Required percentage of renewable energy in portfolio to electric sales																		15.00%					15.00%
Public Service Company of New Mexico | Renewable Portfolio Standard | Required Percentage by 2020
Public Utilities, General Disclosures [Line Items]
Required percentage of renewable energy in portfolio to electric sales																		20.00%					20.00%
Public Service Company of New Mexico | Proposed 2018 Portfolio | Disincentives/Incentives Adder | Subsequent event
Public Utilities, General Disclosures [Line Items]
Number of programs in the proposed program portfolio | program	10
Program portfolio's total budget	$ 25.1
Incentive based on target savings	$ 1.9
Targeted savings (in gigawatt hours) | GWh	53
Public Utilities, Energy Efficiency and Load Management Programs, Projected Earned Incentive	$ 2.1
Public Utilities, Energy Efficiency and Load Management Programs, Targeted Energy Savings | GWh	70
Public Service Company of New Mexico | Proposed 2019 Portfolio | Disincentives/Incentives Adder | Subsequent event
Public Utilities, General Disclosures [Line Items]
Number of programs in the proposed program portfolio | program	10
Program portfolio's total budget	$ 28.2
Incentive based on target savings	$ 2.1
Public Service Company of New Mexico | Renewable Portfolio Standard Supplemental Procurement
Public Utilities, General Disclosures [Line Items]
Number of megawatts of Solar PV facilities | MW																		1.5					1.5
Public Service Company of New Mexico | Renewable Portfolio Standard 2014
Public Utilities, General Disclosures [Line Items]
Number of megawatts for wind energy | MW																		204				102
Public Service Company of New Mexico | Renewable Energy Rider
Public Utilities, General Disclosures [Line Items]
Recorded revenues from renewable rider																		$ 11.0	$ 8.4
Public Service Company of New Mexico | Renewable Energy Rider | Maximum
Public Utilities, General Disclosures [Line Items]
Proposal to collect funds under renewable energy procurement plan																					$ 42.4
Annual revenue to be collected under rider rate																		$ 50.0					$ 50.0
Public Service Company of New Mexico | 2017 Energy Efficiency and Load Management Program | Disincentives/Incentives Adder
Public Utilities, General Disclosures [Line Items]
Number of programs in the proposed program portfolio | program											10
Program portfolio's total budget				$ 26.0							$ 28.0
Incentive based on target savings											$ 2.4
Targeted savings (in gigawatt hours) | GWh											75
Profit incentive				$ 1.8
Public Service Company of New Mexico | Integrated Resource Plan, 2011
Public Utilities, General Disclosures [Line Items]
Frequency of IRP filings																		3 years
Planning period covered of IRP																		20 years
Public Service Company of New Mexico | Advanced Metering Infrastructure Costs
Public Utilities, General Disclosures [Line Items]
Estimated costs to be recovered																											$ 87.2
Estimated future investment																											$ 33.0
Public Service Company of New Mexico | Firm Requirements Wholesale Power Rate Case, Navopache
Public Utilities, General Disclosures [Line Items]
Number of megawatts served under a short-term coordination tariff | MW																		10
Revenue for power sold under PSA																		$ 1.1	$ 5.4
PNMR Development
Public Utilities, General Disclosures [Line Items]
Solar generation capacity (in megawatts) | MW																									30
Construction of solar generation capacity (in megawatts) | MW																									10

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Regulatory and Rate Matters - TNMP Narrative (Details) - Texas-New Mexico Power Company		1 Months Ended	3 Months Ended
	Mar. 13, 2017 USD ($)	Jul. 30, 2011 USD ($)	Mar. 31, 2017 USD ($) customer	Apr. 24, 2017 customer	Dec. 31, 2016 advanced_meter
Public Utilities, General Disclosures [Line Items]
Adjustment of the most recent annual CTC funding amount (greater than or equal to)			15.00%
Requested increase (decrease) adjustment to reduce collection of amortization	$ (1,100,000)
Advanced Meter System Deployment and Surcharge Request
Public Utilities, General Disclosures [Line Items]
Approved deployment costs		$ 113,400,000
Collection of deployment costs through surcharge period		12 years
Number of advanced meters installed | advanced_meter					242,000
Recovery in cost through initial fees			$ 200,000
Ongoing annual expenses			500,000
Approved non-standard metering ongoing expenses monthly charge			$ 36.78
Presumed number of customers that will elect non-standard meter service (in customers) | customer			1,081
Advanced Meter System Deployment and Surcharge Request | Subsequent event
Public Utilities, General Disclosures [Line Items]
Current number of customers that have elected non-standard meter service (in customers) | customer				103
Advanced Meter System Deployment and Surcharge Request | Minimum
Public Utilities, General Disclosures [Line Items]
Approved non-standard metering service cost, initial fee range			$ 63.97
Advanced Meter System Deployment and Surcharge Request | Maximum
Public Utilities, General Disclosures [Line Items]
Approved non-standard metering service cost, initial fee range			$ 168.61

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Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - Texas-New Mexico Power Company - Transmission Cost of Service Rates - USD ($) $ in Millions		6 Months Ended
	Mar. 14, 2017	Mar. 15, 2017	Sep. 09, 2016	Mar. 22, 2016
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base	$ 30.2	$ 9.5	$ 25.8	$ 7.0
Annual Increase in Revenue	$ 4.8	$ 1.8	$ 4.3	$ 1.4

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2014	Dec. 31, 2013
Income Tax Contingency [Line Items]
New Mexico Corporate tax rate before change in 2013				7.60%
New Mexico Corporate tax rate, effective by 2018			5.90%
Increase (decrease) in regulatory liability	$ (4.8)	$ (7.1)
Corporate and Other
Income Tax Contingency [Line Items]
Increase (decrease) in tax expense due to tax rate change (less than for 2017)	0.1	(0.1)
Public Service Company of New Mexico
Income Tax Contingency [Line Items]
Increase (decrease) in deferred tax assets as a result of tax rate changes	(0.1)	(0.7)
Increase (decrease) in tax expense due to tax rate change (less than for 2017)	$ 0.1	$ 0.8

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Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Services billings: | PNMR to PNM
Related Party Transaction [Line Items]
Amount of related party transaction	$ 24,402	$ 22,734
Services billings: | PNMR to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	8,137	7,048
Services billings: | PNM to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	85	106
Services billings: | TNMP to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	35	10
Interest billings: | PNMR to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	31	50
Interest billings: | PNM to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	43	36
Income tax sharing payments: | PNMR to PNM
Related Party Transaction [Line Items]
Amount of related party transaction	0	0
Income tax sharing payments: | PNMR to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	$ 0	$ 0