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 September 30, 2016

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, or a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

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

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 October 21, 2016, 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 October 21, 2016 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 October 21, 2016 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	112
ITEM 4. CONTROLS AND PROCEDURES	115
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	116
ITEM 1A. RISK FACTORS	116
ITEM 6. EXHIBITS	117
SIGNATURE	118

3

GLOSSARY

Definitions:
ABCWUA	Albuquerque Bernalillo County Water Utility Authority
Afton	Afton Generating Station
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
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
CO2	Carbon Dioxide
CSA	Coal Supply Agreement
CTC	Competition Transition Charge
DC Circuit	United States Court of Appeals for the District of Columbia Circuit
Delta	Delta-Person Generating Station, now known as Rio Bravo
DOE	United States Department of Energy
DOI	United States Department of Interior
EGU	Electric Generating Unit
EIP	Eastern Interconnection Project
EIS	Environmental Impact Study
EPA	United States Environmental Protection Agency
ESA	Endangered Species Act
Exchange Act	Securities Exchange Act of 1934
Farmington	The City of Farmington, New Mexico
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIP	Federal Implementation Plan
Four Corners	Four Corners Power Plant
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
IRS	Internal Revenue Service
ISFSI	Independent Spent Fuel Storage Installation
KW	Kilowatt
KWh	Kilowatt Hour
La Luz	La Luz Generating Station
LIBOR	London Interbank Offered Rate
Lightning Dock Geothermal	Lightning Dock geothermal power facility, also known as the Dale Burgett Geothermal Plant
Lordsburg	Lordsburg Generating Station
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 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
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 2014 Term Loan Agreement	PNM’s $175.0 Million Unsecured Term Loan
PNM 2016 Term Loan Agreement	PNM’s $175.0 Million Unsecured Term Loan

5

PNM Multi-draw Term Loan	PNM’s $125.0 Million Unsecured Multi-draw Term Loan Facility
PNM New Mexico Credit Facility	PNM’s $50.0 Million Unsecured Revolving Credit Facility
PNM Revolving Credit Facility	PNM’s $400.0 Million Unsecured Revolving Credit Facility
PNMR	PNM Resources, Inc. and Subsidiaries
PNMR 2015 Term    Loan Agreement	PNMR’s $150.0 Million Three-Year Unsecured Term Loan
PNMR Development	PNMR Development and Management Company, an unregulated wholly-owned subsidiary of PNMR
PNMR Revolving Credit Facility	PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan Agreement	PNMR’s $150.0 Million One-Year Unsecured Term Loan
PPA	Power Purchase Agreement
PSA	Power Sales Agreement
PSD	Prevention of Significant Deterioration
PUCT	Public Utility Commission of Texas
PV	Photovoltaic
PVNGS	Palo Verde Nuclear Generating Station
RA	San Juan Project Restructuring Agreement
RCRA	Resource Conservation and Recovery Act
RCT	Reasonable Cost Threshold
REA	New Mexico’s Renewable Energy Act of 2004
REC	Renewable Energy Certificates
Red Mesa Wind	Red Mesa Wind Energy Center
REP	Retail Electricity Provider
Rio Bravo	Rio Bravo Generating Station, formerly known as Delta
RMC	Risk Management Committee
ROE	Return on Equity
RPS	Renewable Energy Portfolio Standard
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
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 2015 Bond Purchase Agreement	TNMP’s $60.0 Million First Mortgage Bonds
TNMP Revolving Credit Facility	TNMP’s $75.0 Million Secured Revolving Credit Facility
TNP	TNP Enterprises, Inc. and Subsidiaries, a wholly-owned subsidiary of PNMR
Tucson	Tucson Electric Power Company

6

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
WACC	Weighted Average Cost of Capital
WEG	WildEarth Guardians
Westmoreland	Westmoreland Coal Company
Westmoreland Loan	$125.0 Million of funding provided by NM Capital to WSJ
WSJ	Westmoreland San Juan, LLC, an indirect wholly-owned subsidiary of Westmoreland

7

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(In thousands, except per share amounts)
Electric Operating Revenues	$	400,374		$	417,433		$	1,026,726		$	1,103,187
Operating Expenses:
Cost of energy	108,766			124,255			282,498			353,939
Administrative and general	46,942			46,375			139,214			130,161
Energy production costs	31,460			42,168			112,026			129,627
Regulatory disallowances and restructuring costs	16,451			—			17,225			1,744
Depreciation and amortization	53,017			47,503			153,801			139,013
Transmission and distribution costs	16,056			16,768			49,965			50,123
Taxes other than income taxes	19,611			18,859			57,598			55,093
Total operating expenses	292,303			295,928			812,327			859,700
Operating income	108,071			121,505			214,399			243,487
Other Income and Deductions:
Interest income	4,604			1,151			18,420			4,842
Gains on available-for-sale securities	4,531			2,536			15,380			12,116
Other income	4,884			6,165			13,413			16,844
Other (deductions)	(3,764		)	(3,222		)	(10,866		)	(10,591		)
Net other income and deductions	10,255			6,630			36,347			23,211
Interest Charges	32,467			27,528			97,179			86,714
Earnings before Income Taxes	85,859			100,607			153,567			179,984
Income Taxes	27,303			35,752			50,094			61,621
Net Earnings	58,556			64,855			103,473			118,363
(Earnings) Attributable to Valencia Non-controlling Interest	(4,006		)	(3,678		)	(11,037		)	(10,909		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Net Earnings Attributable to PNMR	$	54,418		$	61,045		$	92,040		$	107,058
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.68		$	0.77		$	1.15		$	1.34
Diluted	$	0.68		$	0.76		$	1.15		$	1.34
Dividends Declared per Common Share	$	0.22		$	0.20		$	0.66		$	0.60

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

8

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(In thousands)
Net Earnings	$	58,556		$	64,855		$	103,473		$	118,363
Other Comprehensive Income (Loss):
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit of $(1,877), $1,200, $(1,216) and $(1,213)	2,933			(1,862		)	1,899			1,882
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,985, $3,925, $3,955 and $8,838	(3,101		)	(6,090		)	(6,180		)	(13,714		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience losses recognized as net periodic benefit cost, net of income tax (benefit) of $(537), $(583), $(1,611) and $(1,749)	839			905			2,517			2,715
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $(172), $276, $509 and $276	269			(428		)	(796		)	(428		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(79), $0, $(224) and $0	123			—			349			—
Total Other Comprehensive Income (Loss)	1,063			(7,475		)	(2,211		)	(9,545		)
Comprehensive Income	59,619			57,380			101,262			108,818
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,006		)	(3,678		)	(11,037		)	(10,909		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Comprehensive Income Attributable to PNMR	$	55,481		$	53,570		$	89,829		$	97,513

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

9

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2016			2015
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	103,473		$	118,363
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	178,137			165,563
Deferred income tax expense	50,302			62,511
Net unrealized (gains) losses on commodity derivatives	2,179			1,251
Realized (gains) on available-for-sale securities	(15,380		)	(12,116		)
Stock based compensation expense	4,401			3,748
Regulatory disallowances and restructuring costs	17,225			1,744
Other, net	(954		)	(4,301		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(1,145		)	(23,783		)
Materials, supplies, and fuel stock	(4,629		)	(3,629		)
Other current assets	(11,819		)	37,756
Other assets	1,916			12,350
Accounts payable	6,192			1,275
Accrued interest and taxes	20,816			28,233
Other current liabilities	(19,431		)	(12,731		)
Other liabilities	(10,297		)	(40,662		)
Net cash flows from operating activities	320,986			335,572
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(502,530		)	(411,606		)
Proceeds from sales of available-for-sale securities	280,989			166,097
Purchases of available-for-sale securities	(284,706		)	(166,268		)
Return of principal on PVNGS lessor notes	8,547			21,694
Investment in Westmoreland Loan	(122,250		)	—
Principal repayments on Westmoreland Loan	15,000			—
Other, net	179			2,891
Net cash flows from investing activities	(604,771		)	(387,192		)

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

10

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2016			2015
	(In thousands)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	105,300			(3,000		)
Long-term borrowings	503,500			463,605
Repayment of long-term debt	(288,157		)	(333,066		)
Proceeds from stock option exercise	6,668			7,394
Awards of common stock	(14,920		)	(18,955		)
Dividends paid	(52,967		)	(48,188		)
Valencia’s transactions with its owner	(12,327		)	(12,107		)
Other, net	(1,682		)	(5,402		)
Net cash flows from financing activities	245,415			50,281
Change in Cash and Cash Equivalents	(38,370		)	(1,339		)
Cash and Cash Equivalents at Beginning of Period	46,051			28,274
Cash and Cash Equivalents at End of Period	$	7,681		$	26,935
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	75,537		$	63,046
Income taxes paid (refunded), net	$	850		$	(1,636	)
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	30,208		$	(8,748	)

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

11

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2016		December 31, 2015
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	7,681	$	46,051
Accounts receivable, net of allowance for uncollectible accounts of $1,264 and $1,397	92,060		98,699
Unbilled revenues	57,705		52,012
Other receivables	17,715		28,590
Current portion of Westmoreland Loan	43,553		—
Materials, supplies, and fuel stock	72,015		67,386
Regulatory assets	7,558		1,070
Commodity derivative instruments	3,949		3,813
Income taxes receivable	6,904		5,845
Other current assets	89,746		82,104
Total current assets	398,886		385,570
Other Property and Investments:
Long-term portion of Westmoreland Loan	66,230		—
Available-for-sale securities	271,035		259,042
Other investments	428		604
Non-utility property	3,404		3,404
Total other property and investments	341,097		263,050
Utility Plant:
Plant in service, held for future use, and to be abandoned	6,842,017		6,307,261
Less accumulated depreciation and amortization	2,312,560		2,058,772
	4,529,457		4,248,489
Construction work in progress	227,355		204,766
Nuclear fuel, net of accumulated amortization of $50,623 and $44,455	87,083		82,117
Net utility plant	4,843,895		4,535,372
Deferred Charges and Other Assets:
Regulatory assets	463,016		470,664
Goodwill	278,297		278,297
Commodity derivative instruments	747		2,622
Other deferred charges	77,732		73,753
Total deferred charges and other assets	819,792		825,336
	$	6,403,670	$	6,009,328

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

12

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2016			December 31, 2015
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	355,900		$	250,600
Current installments of long-term debt	101,335			124,979
Accounts payable	76,403			100,419
Customer deposits	11,693			12,216
Accrued interest and taxes	80,180			58,306
Regulatory liabilities	6,403			15,591
Commodity derivative instruments	2,423			1,859
Dividends declared	17,656			17,656
Other current liabilities	49,833			59,494
Total current liabilities	701,826			641,120
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	2,207,005			1,966,969
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	935,796			877,393
Regulatory liabilities	468,979			467,413
Asset retirement obligations	119,032			111,895
Accrued pension liability and postretirement benefit cost	63,437			73,097
Commodity derivative instruments	58			—
Other deferred credits	137,686			133,692
Total deferred credits and other liabilities	1,724,988			1,663,490
Total liabilities	4,633,819			4,271,579
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)	1,162,599			1,166,465
Accumulated other comprehensive income (loss), net of income taxes	(73,643		)	(71,432		)
Retained earnings	599,249			559,780
Total PNMR common stockholders’ equity	1,688,205			1,654,813
Non-controlling interest in Valencia	70,117			71,407
Total equity	1,758,322			1,726,220
	$	6,403,670		$	6,009,328

The accompanying notes, as they relate to PNMR, are an integral part of these 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, 2015	$	1,166,465		$	(71,432	)	$	559,780		$	1,654,813		$	71,407		$	1,726,220
Net earnings before subsidiary preferred stock dividends	—			—			92,436			92,436			11,037			103,473
Total other comprehensive income (loss)	—			(2,211		)	—			(2,211		)	—			(2,211		)
Subsidiary preferred stock dividends	—			—			(396		)	(396		)	—			(396		)
Dividends declared on common stock	—			—			(52,571		)	(52,571		)	—			(52,571		)
Proceeds from stock option exercise	6,668			—			—			6,668			—			6,668
Awards of common stock	(14,920		)	—			—			(14,920		)	—			(14,920		)
Excess tax (shortfall) from stock-based payment arrangements	(15		)	—			—			(15		)	—			(15		)
Stock based compensation expense	4,401			—			—			4,401			—			4,401
Valencia’s transactions with its owner	—			—			—			—			(12,327		)	(12,327		)
Balance at September 30, 2016	$	1,162,599		$	(73,643	)	$	599,249		$	1,688,205		$	70,117		$	1,758,322

The accompanying notes, as they relate to PNMR, are an integral part of these 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(In thousands)
Electric Operating Revenues	$	311,276		$	333,437		$	780,228		$	870,826
Operating Expenses:
Cost of energy	88,565			105,708			222,376			299,302
Administrative and general	41,370			41,927			122,553			118,450
Energy production costs	31,460			42,168			112,026			129,627
Regulatory disallowances and restructuring costs	16,451			—			17,225			1,744
Depreciation and amortization	33,312			29,042			97,778			86,446
Transmission and distribution costs	9,311			10,478			29,868			31,519
Taxes other than income taxes	10,750			10,404			33,289			31,194
Total operating expenses	231,219			239,727			635,115			698,282
Operating income	80,057			93,710			145,113			172,544
Other Income and Deductions:
Interest income	1,509			1,152			8,549			4,869
Gains on available-for-sale securities	4,531			2,536			15,380			12,116
Other income	3,239			5,369			9,578			13,661
Other (deductions)	(2,790		)	(2,616		)	(7,653		)	(7,230		)
Net other income and deductions	6,489			6,441			25,854			23,416
Interest Charges	22,213			19,837			66,494			59,477
Earnings before Income Taxes	64,333			80,314			104,473			136,483
Income Taxes	19,343			27,258			32,131			44,560
Net Earnings	44,990			53,056			72,342			91,923
(Earnings) Attributable to Valencia Non-controlling Interest	(4,006		)	(3,678		)	(11,037		)	(10,909		)
Net Earnings Attributable to PNM	40,984			49,378			61,305			81,014
Preferred Stock Dividends Requirements	(132		)	(132		)	(396		)	(396		)
Net Earnings Available for PNM Common Stock	$	40,852		$	49,246		$	60,909		$	80,618

The accompanying notes, as they relate to PNM, are an integral part of these 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(In thousands)
Net Earnings	$	44,990		$	53,056		$	72,342		$	91,923
Other Comprehensive Income (Loss):
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit of $(1,877), $1,200, $(1,216) and $(1,213)	2,933			(1,862		)	1,899			1,882
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,985, $3,925, $3,955 and $8,838	(3,101		)	(6,090		)	(6,180		)	(13,714		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience losses recognized as net periodic benefit cost, net of income tax (benefit) of $(537), $(583), $(1,611) and $(1,749)	839			905			2,517			2,715
Total Other Comprehensive Income (Loss)	671			(7,047		)	(1,764		)	(9,117		)
Comprehensive Income	45,661			46,009			70,578			82,806
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,006		)	(3,678		)	(11,037		)	(10,909		)
Comprehensive Income Attributable to PNM	$	41,655		$	42,331		$	59,541		$	71,897

The accompanying notes, as they relate to PNM, are an integral part of these 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)

	Nine Months Ended September 30,
	2016			2015
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	72,342		$	91,923
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	122,344			111,371
Deferred income tax expense	33,175			46,268
Net unrealized (gains) losses on commodity derivatives	2,179			1,251
Realized (gains) on available-for-sale securities	(15,380		)	(12,116		)
Regulatory disallowances and restructuring costs	17,225			1,744
Other, net	(563		)	(5,288		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	8,283			(16,220		)
Materials, supplies, and fuel stock	(7,731		)	(3,328		)
Other current assets	(4,005		)	36,707
Other assets	10,117			12,126
Accounts payable	6,819			(794		)
Accrued interest and taxes	16,146			22,856
Other current liabilities	(18,908		)	(12,099		)
Other liabilities	(13,401		)	(34,224		)
Net cash flows from operating activities	228,642			240,177
Cash Flows From Investing Activities:
Utility plant additions	(377,637		)	(301,410		)
Proceeds from sales of available-for-sale securities	280,989			166,097
Purchases of available-for-sale securities	(284,706		)	(166,268		)
Return of principal on PVNGS lessor notes	8,547			21,694
Other, net	171			3,051
Net cash flows from investing activities	(372,636		)	(276,836		)

The accompanying notes, as they relate to PNM, are an integral part of these 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)

	Nine Months Ended September 30,
	2016			2015
	(In thousands)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	42,400			—
Long-term borrowings	321,000			313,605
Repayment of long-term debt	(271,000		)	(214,300		)
Equity contribution from parent	28,142			—
Dividends paid	(4,538		)	(46,548		)
Valencia’s transactions with its owner	(12,327		)	(12,107		)
Other, net	(928		)	(4,934		)
Net cash flows from financing activities	102,749			35,716
Change in Cash and Cash Equivalents	(41,245		)	(943		)
Cash and Cash Equivalents at Beginning of Period	43,138			25,480
Cash and Cash Equivalents at End of Period	$	1,893		$	24,537
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	53,791		$	42,680
Income taxes paid (refunded), net	$	—		$	(1,450	)
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	20,200		$	(9,933	)

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

18

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2016		December 31, 2015
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1,893	$	43,138
Accounts receivable, net of allowance for uncollectible accounts of $1,264 and $1,397	63,109		78,291
Unbilled revenues	47,450		42,641
Other receivables	15,676		24,725
Affiliate receivables	8,956		15,105
Materials, supplies, and fuel stock	68,208		60,477
Regulatory assets	4,364		—
Commodity derivative instruments	3,949		3,813
Income taxes receivable	15,621		14,577
Other current assets	81,419		74,990
Total current assets	310,645		357,757
Other Property and Investments:
Available-for-sale securities	271,035		259,042
Other investments	197		366
Non-utility property	96		96
Total other property and investments	271,328		259,504
Utility Plant:
Plant in service, held for future use, and to be abandoned	5,303,910		4,833,303
Less accumulated depreciation and amortization	1,785,507		1,569,549
	3,518,403		3,263,754
Construction work in progress	152,940		172,238
Nuclear fuel, net of accumulated amortization of $50,623 and $44,455	87,083		82,117
Net utility plant	3,758,426		3,518,109
Deferred Charges and Other Assets:
Regulatory assets	335,025		342,910
Goodwill	51,632		51,632
Commodity derivative instruments	747		2,622
Other deferred charges	71,209		66,810
Total deferred charges and other assets	458,613		463,974
	$	4,799,012	$	4,599,344

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

19

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2016			December 31, 2015
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	42,400		$	—
Current installments of long-term debt	56,862			124,979
Accounts payable	59,003			72,386
Affiliate payables	15,082			14,318
Customer deposits	11,693			12,216
Accrued interest and taxes	50,379			33,189
Regulatory liabilities	6,403			15,591
Commodity derivative instruments	2,423			1,859
Dividends declared	132			132
Other current liabilities	31,606			42,251
Total current liabilities	275,983			316,921
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,574,725			1,455,698
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	737,780			696,384
Regulatory liabilities	434,755			434,863
Asset retirement obligations	118,133			111,049
Accrued pension liability and postretirement benefit cost	57,057			66,285
Commodity derivative instruments	58			—
Other deferred credits	117,797			117,275
Total deferred credits and liabilities	1,465,580			1,425,856
Total liabilities	3,316,288			3,198,475
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			1,236,776
Accumulated other comprehensive income (loss), net of income taxes	(73,240		)	(71,476		)
Retained earnings	209,400			152,633
Total PNM common stockholder’s equity	1,401,078			1,317,933
Non-controlling interest in Valencia	70,117			71,407
Total equity	1,471,195			1,389,340
	$	4,799,012		$	4,599,344

The accompanying notes, as they relate to PNM, are an integral part of these 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, 2015	$	1,236,776	$	(71,476	)	$	152,633		$	1,317,933		$	71,407		$	1,389,340
Net earnings	—		—			61,305			61,305			11,037			72,342
Total other comprehensive income (loss)	—		(1,764		)	—			(1,764		)	—			(1,764		)
Dividends declared on preferred stock	—		—			(396		)	(396		)	—			(396		)
Equity contribution from parent	28,142		—			—			28,142			—			28,142
Dividends declared on common stock	—		—			(4,142		)	(4,142		)	—			(4,142		)
Valencia’s transactions with its owner	—		—			—			—			(12,327		)	(12,327		)
Balance at September 30, 2016	$	1,264,918	$	(73,240	)	$	209,400		$	1,401,078		$	70,117		$	1,471,195

The accompanying notes, as they relate to PNM, are an integral part of these 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(In thousands)
Electric Operating Revenues	$	89,098		$	83,996		$	246,498		$	232,361
Operating Expenses:
Cost of energy	20,201			18,547			60,122			54,637
Administrative and general	9,588			9,071			29,382			26,946
Depreciation and amortization	16,354			15,016			45,760			42,065
Transmission and distribution costs	6,745			6,290			20,097			18,604
Taxes other than income taxes	7,851			7,405			20,849			19,782
Total operating expenses	60,739			56,329			176,210			162,034
Operating income	28,359			27,667			70,288			70,327
Other Income and Deductions:
Other income	1,376			774			2,999			3,106
Other (deductions)	(521		)	(102		)	(860		)	(349		)
Net other income and deductions	855			672			2,139			2,757
Interest Charges	7,308			6,855			22,150			20,636
Earnings before Income Taxes	21,906			21,484			50,277			52,448
Income Taxes	8,053			7,795			18,460			19,200
Net Earnings	$	13,853		$	13,689		$	31,817		$	33,248

The accompanying notes, as they relate to TNMP, are an integral part of these 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)

	Nine Months Ended September 30,
	2016			2015
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	31,817		$	33,248
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	47,055			43,272
Deferred income tax expense	(739		)	3,575
Other, net	(391		)	(125		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(9,428		)	(7,563		)
Materials and supplies	3,102			(301		)
Other current assets	(3,570		)	2,712
Other assets	(8,415		)	(272		)
Accounts payable	(6,758		)	(210		)
Accrued interest and taxes	22,896			19,757
Other current liabilities	(363		)	1,033
Other liabilities	399			(5,870		)
Net cash flows from operating activities	75,605			89,256
Cash Flows From Investing Activities:
Utility plant additions	(93,048		)	(90,497		)
Net cash flows from investing activities	(93,048		)	(90,497		)
Cash Flow From Financing Activities:
Revolving credit facilities borrowings (repayments), net	(59,000		)	(5,000		)
Short-term borrowings (repayments) – affiliate, net	(11,800		)	25,800
Long-term borrowings	60,000			—
Equity contribution from parent	50,000			—
Dividends paid	(17,965		)	(19,559		)
Other, net	(775		)	—
Net cash flows from financing activities	20,460			1,241
Change in Cash and Cash Equivalents	3,017			—
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	3,018		$	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	15,642		$	13,308
Income taxes paid (refunded), net	$	850		$	545
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	(10	)	$	(216	)

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

23

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2016		December 31, 2015
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	3,018	$	1
Accounts receivable	28,951		20,408
Unbilled revenues	10,255		9,371
Other receivables	1,129		811
Materials and supplies	3,807		6,909
Regulatory assets	3,194		1,070
Other current assets	2,167		1,053
Total current assets	52,521		39,623
Other Property and Investments:
Other investments	231		238
Non-utility property	2,240		2,240
Total other property and investments	2,471		2,478
Utility Plant:
Plant in service and plant held for future use	1,342,081		1,285,727
Less accumulated depreciation and amortization	435,245		406,516
	906,836		879,211
Construction work in progress	45,580		16,561
Net utility plant	952,416		895,772
Deferred Charges and Other Assets:
Regulatory assets	127,991		127,754
Goodwill	226,665		226,665
Other deferred charges	4,776		4,847
Total deferred charges and other assets	359,432		359,266
	$	1,366,840	$	1,297,139

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

24

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2016		December 31, 2015
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	—	$	59,000
Short-term debt – affiliate	—		11,800
Accounts payable	9,258		16,006
Affiliate payables	2,346		3,681
Accrued interest and taxes	55,788		32,891
Other current liabilities	3,012		2,044
Total current liabilities	70,404		125,422
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	420,802		361,411
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	232,218		232,791
Regulatory liabilities	34,224		32,550
Asset retirement obligations	739		695
Accrued pension liability and postretirement benefit cost	6,380		6,812
Other deferred credits	4,841		4,078
Total deferred credits and other liabilities	278,402		276,926
Total liabilities	769,608		763,759
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		404,166
Retained earnings	143,002		129,150
Total common stockholder’s equity	597,232		533,380
	$	1,366,840	$	1,297,139

The accompanying notes, as they relate to TNMP, are an integral part of these 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, 2015	$	64	$	404,166	$	129,150		$	533,380
Net earnings	—		—		31,817			31,817
Equity contribution from parent	—		50,000		—			50,000
Dividends declared on common stock	—		—		(17,965		)	(17,965		)
Balance at September 30, 2016	$	64	$	454,166	$	143,002		$	597,232

The accompanying notes, as they relate to TNMP, are an integral part of these 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 September 30, 2016 and December 31, 2015, the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2016 and 2015, and cash flows for the nine months ended September 30, 2016 and 2015. 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 2015 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2016 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 2015 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.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.22 per share in July 2016 and $0.20 in July

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)

2015, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. The Board declared dividends on common stock considered to be for the third quarter of $0.22 per share in September 2016 and $0.20 per share in September 2015, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

In the nine months ended September 30, 2016, PNMR made equity contributions of $28.1 million to PNM and $50.0 million to TNMP. PNM declared and paid cash dividends on common stock to PNMR of $4.1 million and $46.2 million in the nine months ended September 30, 2016 and 2015. TNMP declared and paid cash dividends on common stock to PNMR of $18.0 million and $19.6 million in the nine months ended September 30, 2016 and 2015.

New Accounting Pronouncements

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

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

In May 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. When it becomes effective, the new standard will replace most existing revenue recognition guidance in GAAP. In August 2015, the FASB issued a one-year deferral in the effective date. Since the issuance of ASU No. 2014-09, the FASB also has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. The Company must adopt ASU 2014-09 beginning on January 1, 2018. Early adoption would be permitted beginning January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method although it is unlikely the Company would elect to early adopt the new standard. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures, but has not determined the effect of the standard on its financial reporting.

Accounting Standards Update 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

In August 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company anticipates adopting this standard as of December 31, 2016. The Company is 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 2016-01 – 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. The new standard will be effective for the Company beginning on January 1, 2018. Early adoption of the standard is permitted. The Company is in the process of analyzing the impacts of this new standard.

28

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Accounting Standards Update 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. The new standard will be effective for the Company beginning on January 1, 2019. Early adoption of the standard is permitted. At adoption of the ASU, leases will be recognized and measured as of the earliest period presented using a modified retrospective approach. The Company is in the process of analyzing the impacts of this new standard.

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

In March 2016, the FASB issued ASU No. 2016-09. The ASU simplifies several aspects of the accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Currently, tax benefits resulting from deductions in excess of compensation cost on vested restricted stock and performance awards and on exercised stock options (“excess tax benefits”) are recorded to equity provided these benefits reduce taxes payable. Tax deficiencies resulting from deductions related to awards, which are below realized compensation cost upon vesting and on canceled stock options are recorded to equity. The Company has not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. Upon implementation of the new standard, the Company will record a cumulative effect adjustment to recognize excess tax benefits that have not been recorded due to the Company’s net operating loss. Subsequent to implementation, all excess tax benefits and deficiencies will be recorded to tax expense on the Condensed Consolidated Income Statements and classified as cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. The Company continues its process of analyzing the impacts of this new standard, but does not believe there will be any retrospective impacts to its financial statements. The Company anticipates adopting the new standard upon its required effective date of January 1, 2017.

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. The new standard is effective for the Company beginning on January 1, 2018.  Early adoption is permitted including adoption in an interim period.   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.

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)

(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				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	54,418	$	61,045	$	92,040	$	107,058
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	96		100		99		103
Average Shares – Basic	79,750		79,754		79,753		79,757
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	367		362		377		377
Average Shares – Diluted	80,117		80,116		80,130		80,134
Net Earnings Per Share of Common Stock:
Basic	$	0.68	$	0.77	$	1.15	$	1.34
Diluted	$	0.68	$	0.76	$	1.15	$	1.34

(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 provides generation service to firm-requirements wholesale customers and sells electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM’s jurisdictional capacity, as well as the capacity from PVNGS Unit 3, which currently is not included in retail rates (Note 11). FERC has jurisdiction over wholesale power and transmission rates.

TNMP

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

Corporate and Other

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

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)

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 September 30, 2016
Electric operating revenues	$	311,276		$	89,098		$	—		$	400,374
Cost of energy	88,565			20,201			—			108,766
Utility margin	222,711			68,897			—			291,608
Other operating expenses	109,342			24,184			(3,006		)	130,520
Depreciation and amortization	33,312			16,354			3,351			53,017
Operating income (loss)	80,057			28,359			(345		)	108,071
Interest income	1,509			—			3,095			4,604
Other income (deductions)	4,980			855			(184		)	5,651
Interest charges	(22,213		)	(7,308		)	(2,946		)	(32,467		)
Segment earnings (loss) before income taxes	64,333			21,906			(380		)	85,859
Income taxes (benefit)	19,343			8,053			(93		)	27,303
Segment earnings (loss)	44,990			13,853			(287		)	58,556
Valencia non-controlling interest	(4,006		)	—			—			(4,006		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	40,852		$	13,853		$	(287	)	$	54,418
Nine Months Ended September 30, 2016
Electric operating revenues	$	780,228		$	246,498		$	—		$	1,026,726
Cost of energy	222,376			60,122			—			282,498
Utility margin	557,852			186,376			—			744,228
Other operating expenses	314,961			70,328			(9,261		)	376,028
Depreciation and amortization	97,778			45,760			10,263			153,801
Operating income (loss)	145,113			70,288			(1,002		)	214,399
Interest income	8,549			—			9,871			18,420
Other income (deductions)	17,305			2,139			(1,517		)	17,927
Interest charges	(66,494		)	(22,150		)	(8,535		)	(97,179		)
Segment earnings (loss) before income taxes	104,473			50,277			(1,183		)	153,567
Income taxes (benefit)	32,131			18,460			(497		)	50,094
Segment earnings (loss)	72,342			31,817			(686		)	103,473
Valencia non-controlling interest	(11,037		)	—			—			(11,037		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	60,909		$	31,817		$	(686	)	$	92,040
At September 30, 2016:
Total Assets	$	4,799,012		$	1,366,840		$	237,818		$	6,403,670
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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)

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2015
Electric operating revenues	$	333,437		$	83,996		$	—		$	417,433
Cost of energy	105,708			18,547			—			124,255
Utility margin	227,729			65,449			—			293,178
Other operating expenses	104,977			22,766			(3,573		)	124,170
Depreciation and amortization	29,042			15,016			3,445			47,503
Operating income	93,710			27,667			128			121,505
Interest income	1,152			—			(1		)	1,151
Other income (deductions)	5,289			672			(482		)	5,479
Interest charges	(19,837		)	(6,855		)	(836		)	(27,528		)
Segment earnings (loss) before income taxes	80,314			21,484			(1,191		)	100,607
Income taxes (benefit)	27,258			7,795			699			35,752
Segment earnings (loss)	53,056			13,689			(1,890		)	64,855
Valencia non-controlling interest	(3,678		)	—			—			(3,678		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	49,246		$	13,689		$	(1,890	)	$	61,045
Nine Months Ended September 30, 2015
Electric operating revenues	$	870,826		$	232,361		$	—		$	1,103,187
Cost of energy	299,302			54,637			—			353,939
Utility margin	571,524			177,724			—			749,248
Other operating expenses	312,534			65,332			(11,118		)	366,748
Depreciation and amortization	86,446			42,065			10,502			139,013
Operating income	172,544			70,327			616			243,487
Interest income	4,869			—			(27		)	4,842
Other income (deductions)	18,547			2,757			(2,935		)	18,369
Interest charges	(59,477		)	(20,636		)	(6,601		)	(86,714		)
Segment earnings (loss) before income taxes	136,483			52,448			(8,947		)	179,984
Income taxes (benefit)	44,560			19,200			(2,139		)	61,621
Segment earnings (loss)	91,923			33,248			(6,808		)	118,363
Valencia non-controlling interest	(10,909		)	—			—			(10,909		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	80,618		$	33,248		$	(6,808	)	$	107,058
At September 30, 2015:
Total Assets	$	4,615,442		$	1,282,766		$	114,374		$	6,012,582
Goodwill	$	51,632		$	226,665		$	—		$	278,297

At December 31, 2015, the Company adopted ASU 2015-03 – Interest – Imputation of Interest (Subtopic 835-30) and ASU 2015-17, Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes, which require that debt issuance costs be reflected as a direct reduction of the related debt liability, except for arrangements such as the Company’s revolving credit facilities, and eliminated the requirement to classify deferred tax assets and liabilities as non-current or current. The Company applied the updates retrospectively to make all periods comparable. As a result, amounts previously reported as total assets at September 30, 2015 above have been reduced to reflect the reclassifications aggregating $40.3 million for PNMR, $22.1 million for PNM, and $10.4 million for TNMP.

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 nine months ended September 30, 2016 and 2015 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, 2015	$	17,346		$	(88,822	)	$	(71,476	)	$	44		$	(71,432	)
Amounts reclassified from AOCI (pre-tax)	(10,135		)	4,128			(6,007		)	573			(5,434		)
Income tax impact of amounts reclassified	3,955			(1,611		)	2,344			(224		)	2,120
Other OCI changes (pre-tax)	3,115			—			3,115			(1,305		)	1,810
Income tax impact of other OCI changes	(1,216		)	—			(1,216		)	509			(707		)
Net change after income taxes	(4,281		)	2,517			(1,764		)	(447		)	(2,211		)
Balance at September 30, 2016	$	13,065		$	(86,305	)	$	(73,240	)	$	(403	)	$	(73,643	)

Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—		$	(61,755	)
Amounts reclassified from AOCI (pre-tax)	(22,552		)	4,464			(18,088		)	—			(18,088		)
Income tax impact of amounts reclassified	8,838			(1,749		)	7,089			—			7,089
Other OCI changes (pre-tax)	3,095			—			3,095			(704		)	2,391
Income tax impact of other OCI changes	(1,213		)	—			(1,213		)	276			(937		)
Net change after income taxes	(11,832		)	2,715			(9,117		)	(428		)	(9,545		)
Balance at September 30, 2015	$	16,176		$	(87,048	)	$	(70,872	)	$	(428	)	$	(71,300	)

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 nine months ended September 30, 2016 and 2015, 24.3% and 22.4% of the pension amounts reclassified were capitalized into construction work in process and 2.5% and 2.5% 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 2015 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 operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and nine months ended September 30, 2016, PNM paid $4.9 million and $14.5 million for fixed charges and $0.5 million and $1.1 million for variable charges. For the three and nine months ended September 30, 2015, PNM paid $4.9 million and $14.5 million for fixed charges and $0.3 million and $0.9 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM 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. 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(In thousands)
Operating revenues	$	5,356		$	5,182		$	15,541		$	15,337
Operating expenses	(1,350		)	(1,504		)	(4,504		)	(4,428		)
Earnings attributable to non-controlling interest	$	4,006		$	3,678		$	11,037		$	10,909

Financial Position

	September 30,		December 31,
	2016		2015
	(In thousands)
Current assets	$	3,506	$	2,588
Net property, plant, and equipment	67,656		69,784
Total assets	71,162		72,372
Current liabilities	1,045		965
Owners’ equity – non-controlling interest	$	70,117	$	71,407

During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the VIE. The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market

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)

value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process was initiated since the parties failed to reach agreement on fair market value within 60 days. Under the PPA, results of the appraisal process established the purchase price after which PNM was to determine in its sole discretion whether or not to exercise its option to purchase the 50% interest. The PPA also provides that the purchase price may be adjusted to reflect the period between the determination of the purchase price and the closing. The appraisal process determined the purchase price as of October 8, 2013 to be $85.0 million, prior to any adjustment to reflect the period through the closing date. Approval of the NMPRC and FERC would be required, which process could take up to 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. The owner of Valencia submitted a counter-proposal to PNM in April 2015 and the parties are continuing to have periodic discussions. PNM cannot predict if it will reach agreement with the owner of Valencia, if required regulatory and other approvals will be received, or if the purchase will be completed.

PVNGS Leases

PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which initially were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. At January 15, 2015, the four Unit 1 leases were extended. At January 15, 2016, one of the Unit 2 leases was extended and PNM exercised its fair market value options to purchase the assets underlying the other three Unit 2 leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K and Note 6 for additional information regarding the leases, including PNM’s actions regarding the renewal and purchase options. See Note 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case.

Each of the lease agreements is with a different trust whose beneficial owner is an institutional investor. PNM is not the legal or tax owner of the leased assets. The beneficial owners of the trusts possess all of the voting control and pecuniary interest in the trusts. PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments and other than as discussed in Note 6, PNM has no other financial obligations or commitments to the trusts or the beneficial owners although PNM is responsible for all decommissioning obligations related to its entire interest in PVNGS both during and after termination of the leases. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its Condensed Consolidated Balance Sheets related to the trusts other than accrued lease payments of $3.8 million at September 30, 2016 and $18.4 million at December 31, 2015, which are included in other current liabilities on the Condensed Consolidated Balance Sheets.

Prior to their exercise or expiration, PNM’s fixed rate renewal options were considered to be variable interests in the trusts and resulted in the trusts being considered VIEs under GAAP. PNM evaluated the PVNGS lease arrangements, including actions taken with respect to the renewal and purchase options, and concluded that it did not have the power to direct the activities that most significantly impacted the economic performance of the trusts and, therefore, was not the primary beneficiary of the trusts under GAAP. Upon execution of documents establishing terms of the asset purchases or lease extensions, PNM’s variable interest in the trusts ceased to exist.

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 a $40.0 million letter of credit support under the PNMR Revolving Credit Facility 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 letter of credit support result in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital could be subject to loss in the event WSJ were to default under the Westmoreland Lo

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)

an and/or performance under the letter of credit support was required.  Principal payments under the Westmoreland Loan began on August 1, 2016 and are required quarterly thereafter. Interest is also paid quarterly beginning on May 1, 2016.

At September 30, 2016, the amount outstanding under the Westmoreland Loan was $110.0 million, after the August 1, 2016 scheduled principal payment of $15.0 million, and is reflected on the Condensed Consolidated Balance Sheet net of unamortized fees. In addition, interest receivable of $1.5 million is included in Other receivables. In August 2016, the $40.0 million letter of credit support was reduced to $30.3 million. 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 $15.0 million plus interest of $2.3 million is due on November 1, 2016. As of October 21, 2016, $17.3 million was held in a 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. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations.  In such event, NM Capital would likely engage a third-party mining company to operate SJCC so that operations of the mine are not disrupted. Since the acquisition of SJCC by WSJ for approximately $125.0 million is a recently negotiated, arms-length transaction between Westmoreland and BHP, the amount should approximate the fair value of SJCC.  Therefore, if WSJ were to default, NM Capital should be able to acquire assets of approximately the value of the Westmoreland Loan without a significant loss. Furthermore, PNMR considers the possibility of loss under the letter of credit support to be remote since the purpose of posting the bonds is to provide assurance that SJCC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the CSA. Also, much of the mine reclamation activities will not be performed for many years in the future, including after the expiration of the CSA and the final maturity of the Westmoreland Loan. In addition, each of the SJGS participants has established, and funds, a trust to meet its future reclamation obligations.

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

(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 and, through April 1, 2015, leased an interest in the EIP transmission line. 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 2015 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 31.25 MW of the entitlement from PVNGS Unit 2 and $85.2 million to the lessors under the other two leases for 32.76 MW of the entitlement from PVNGS Unit 2. See Note 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case.

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)

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 September 30, 2016, amounts due to the lessors under the circumstances described above would be up to $176.1 million, payable on January 15, 2017 in addition to the scheduled lease payments due on January 15, 2017.

At March 31, 2015, PNM owned 60% of the EIP and leased the other 40%, under a lease that expired on April 1, 2015. PNM purchased the leased capacity at fair market value, which the parties agreed was $7.7 million, on April 1, 2015.

(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 2015 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 for commodity derivatives 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 fair values, there are inherent limitations in any estimation technique.

Energy Related Derivative Contracts

Overview

The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. PNM’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. However, as discussed below, PNM has hedging arrangements for the output of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases.

Commodity Risk

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

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)

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 nine months ended September 30, 2016 and the year ended December 31, 2015, 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
	September 30, 2016			December 31, 2015
PNMR and PNM	(In thousands)
Current assets	$	3,949		$	3,813
Deferred charges	747			2,622
	4,696			6,435
Current liabilities	(2,423		)	(1,859		)
Long-term liabilities	(58		)	—
	(2,481		)	(1,859		)
Net	$	2,215		$	4,576

Included in the above table are $2.7 million of current assets and $0.6 million of deferred charges at September 30, 2016 and $3.0 million of current assets and $2.6 million of deferred charges at December 31, 2015 related to contracts for the sale of energy from PVNGS Unit 3 through 2017 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at September 30, 2016 and December 31, 2015.

At September 30, 2016 and December 31, 2015, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at September 30, 2016 and December 31, 2015, amounts posted as cash collateral under margin arrangements were $3.0 million and $2.7 million for both PNMR and PNM. At September 30, 2016 and December 31, 2015, obligations to return cash collateral were $0.1 million and $0.1 million for both PNMR and PNM. Cash collateral amounts are included in other current assets and other current liabilities on the 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, less than $0.1 million of deferred charges, and less than $0.1 million of current liabilities at September 30, 2016 and $0.4 million of current assets and $0.2 million of current liabilities at December 31, 2015 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.

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)

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						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
PNMR and PNM	(In thousands)
Electric operating revenues	$	1,652		$	6,823		$	214		$	7,354
Cost of energy	(1		)	(78		)	(1,113		)	(227		)
Total gain (loss)	$	1,651		$	6,745		$	(899	)	$	7,127

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
September 30, 2016	200,000	(2,924,985	)
December 31, 2015	577,481	(3,405,843	)

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

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

Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
PNMR and PNM
September 30, 2016	$	—	$	—	$	—
December 31, 2015	$	839	$	—	$	839

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently included in retail rates, that unit’s power is being sold in the wholesale market. PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers beginning on January 1, 2018. As of September 30, 2016, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2017, at market price plus a premium.  Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates for substantially all of the sales through 2017, which average approximately $26 per MWh in 2016 and $29 per MWh in 2017.

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)

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 post-term reclamation costs related to the coal mines serving SJGS and Four Corners (Note 11). At September 30, 2016 and December 31, 2015, the fair value of available-for-sale securities included $258.6 million and $249.1 million for the NDT and $12.4 million and $9.9 million for the mine reclamation trusts. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	September 30, 2016				December 31, 2015
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	4,831	$	—	$	10,700
Equity securities:
Domestic value	8,345		63,666		11,610		44,505
Domestic growth	5,619		47,996		11,163		61,078
International and other	2,868		28,304		1,569		27,961
Fixed income securities:
U.S. Government	696		37,152		178		27,880
Municipals	2,490		52,459		3,672		58,576
Corporate and other	1,698		36,627		628		28,342
	$	21,716	$	271,035	$	28,820	$	259,042

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the change in realized impairment losses of $0.1 million and $1.0 million for the three and nine months ended September 30, 2016 and $(2.4) million and $(3.2) million for the three and nine months ended September 30, 2015.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In thousands)
Proceeds from sales	$	86,975		$	71,576		$	280,989		$	166,097
Gross realized gains	$	7,026		$	8,998		$	27,273		$	22,463
Gross realized (losses)	$	(2,565	)	$	(4,014	)	$	(12,913	)	$	(7,133	)

Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. At September 30, 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.

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)

At September 30, 2016, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR
	(In thousands)
Within 1 year	$	4,349	$	—
After 1 year through 5 years	36,265		119,987
After 5 years through 10 years	24,512		—
After 10 years through 15 years	10,286		—
After 15 years through 20 years	9,446		—
After 20 years	41,380		—
	$	126,238	$	119,987

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 nine months ended September 30, 2016 and the year ended December 31, 2015.

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

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)

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 September 30, 2016 and December 31, 2015 for items recorded at fair value.

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2016	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	4,831		$	4,831	$	—
Equity securities:
Domestic value	63,666			63,666		—
Domestic growth	47,996			47,996		—
International and other	28,304			28,304		—
Fixed income securities:
U.S. Government	37,152			35,879		1,273
Municipals	52,459			—		52,459
Corporate and other	36,627			6,849		29,778
	$	271,035		$	187,525	$	83,510
Commodity derivative assets	$	4,696		$	—	$	4,696
Commodity derivative liabilities	(2,481		)	—		(2,481		)
Net	$	2,215		$	—	$	2,215
December 31, 2015
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	10,700		$	10,700	$	—
Equity securities:
Domestic value	44,505			44,505		—
Domestic growth	61,078			61,078		—
International and other	27,961			27,961		—
Fixed income securities:
U.S. Government	27,880			26,608		1,272
Municipals	58,576			—		58,576
Corporate and other	28,342			6,500		21,842
	$	259,042		$	177,352	$	81,690
Commodity derivative assets	$	6,435		$	—	$	6,435
Commodity derivative liabilities	(1,859		)	—		(1,859		)
Net	$	4,576		$	—	$	4,576

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)

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
September 30, 2016	(In thousands)
PNMR
Long-term debt	$	2,308,340	$	2,508,344	$	—	$	2,508,344	$	—
Westmoreland Loan	$	109,783	$	119,987	$	—	$	—	$	119,987
Other investments	$	428	$	1,030	$	428	$	—	$	602
PNM
Long-term debt	$	1,631,587	$	1,768,115	$	—	$	1,768,115	$	—
Other investments	$	197	$	197	$	197	$	—	$	—
TNMP
Long-term debt	$	420,802	$	482,385	$	—	$	482,385	$	—
Other investments	$	231	$	231	$	231	$	—	$	—
December 31, 2015
PNMR
Long-term debt	$	2,091,948	$	2,264,869	$	—	$	2,264,869	$	—
Investment in PVNGS lessor notes	$	8,587	$	8,947	$	—	$	—	$	8,947
Other investments	$	604	$	1,269	$	604	$	—	$	665
PNM
Long-term debt	$	1,580,677	$	1,703,209	$	—	$	1,703,209	$	—
Investment in PVNGS lessor notes	$	8,587	$	8,947	$	—	$	—	$	8,947
Other investments	$	366	$	366	$	366	$	—	$	—
TNMP
Long-term debt	$	361,411	$	411,661	$	—	$	411,661	$	—
Other investments	$	238	$	238	$	238	$	—	$	—

(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 2015 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.

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

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)

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 September 30, 2016 and December 31, 2015, PNMR had unrecognized expense related to stock awards of $5.9 million and $5.7 million, which are expected to be recognized over an average of 1.9 and 1.4 years. 

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:

	Nine Months Ended September 30,
Restricted Shares and Performance Based Shares	2016			2015
Expected quarterly dividends per share	$	0.22		$	0.20
Risk-free interest rate	0.94		%	0.92		%
Market-Based Shares
Dividend yield	2.74		%	2.87		%
Expected volatility	20.44		%	18.73		%
Risk-free interest rate	0.97		%	1.00		%

The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the nine months endedSeptember 30, 2016:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2015	245,094		$	24.81	569,342		$	19.35
Granted	190,276		$	26.49	—		$	—
Exercised	(213,812	)	$	23.44	(241,468	)	$	27.61
Forfeited	(714	)	$	29.54	(2,000	)	$	12.22
Expired	—		$	—	(8,200	)	$	24.85
Outstanding at September 30, 2016	220,844		$	27.58	317,674		$	12.97

PNMR’s stock-based compensation program provides for performance and market targets through 2018. Included as granted and exercised in the above table are 79,619 previously awarded shares that were earned for the 2013 through 2015 performance measurement period and approved by the Board in February 2016 (based upon achieving market targets at “target” levels, weighted at 60%, and performance targets at “threshold” levels, weighted at 40%). Excluded from the above table are maximums of 165,628, 166,797, and 147,031 shares for the three-year performance periods ending in 2016, 2017, and 2018 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR’s common stock if PNMR meets specific market targets at the end of 2016 and she remains an employee of the Company. Under the agreement, she would receive 35,000 of the total shares if

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)

PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2014 and the Board approved her receiving the 35,000 shares in February 2015. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2016, he would receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. If the target for the first performance period is not met, but the target for the second performance period is met, he would receive both awards, less any amount received previously under the agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include any restricted stock shares under this retention award agreement.

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

At September 30, 2016, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.3 million with a weighted-average remaining contract life of 2.22 years. At September 30, 2016, no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date.

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

	Nine Months Ended September 30,
Restricted Stock	2016		2015
Weighted-average grant date fair value	$	26.49	$	20.34
Total fair value of restricted shares that vested (in thousands)	$	5,011	$	6,503
Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	—
Total intrinsic value of options exercised (in thousands)	$	1,208	$	1,814

(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. Each of the revolving credit facilities and the Company’s term loans contains one financial covenant, which requires the maintenance of debt-to-capital ratios of less than or equal to 65% and generally include customary covenants, events of default, cross default provisions, and change of control provisions. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. Additional information concerning financing activities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K.

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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)

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, which was 1.42% at September 30, 2016, 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 loss of $0.7 million at September 30, 2016, which is included in Other deferred credits on the Condensed Consolidated Balance Sheets, and a fair value gain of $0.1 million at December 31, 2015, using Level 2 inputs under GAAP determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.

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, 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 3.51% at September 30, 2016. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding of $125.0 million (the “Westmoreland Loan”) to a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price of the stock of SJCC. The BTMU Term Loan Agreement provides that the amount outstanding thereunder must be reduced by at least $5.0 million quarterly beginning on November 1, 2016. NM Capital is also required to utilize the net proceeds of all amounts received under the Westmoreland Loan, after income taxes and fees, to make principal and interest payments on the BTMU Term Loan Agreement. The principal balance outstanding under the BTMU Term Loan Agreement was $107.8 million at September 30, 2016. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $45.1 million on the BTMU Term Loan Agreement in the twelve months ended September 30, 2017.

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

On May 20, 2016, PNM entered into a $175.0 million term loan agreement (the “PNM 2016 Term Loan Agreement”) between PNM and JPMorgan Chase Bank, N.A., as lender and administrative agent. The PNM 2016 Term Loan Agreement bears interest at a variable rate, which was 1.15% at September 30, 2016, and has a maturity date of November 17, 2017. PNM used a portion of the proceeds of the PNM 2016 Term Loan Agreement to prepay without penalty the $125.0 million outstanding under the PNM Multi-draw Term Loan, which had a scheduled maturity of June 21, 2016.

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

On October 21, 2016, PNMR entered into a letter of credit arrangement with JPMorgan Chase Bank, N.A. under which letters of credit aggregating $30.3 million (the “JPM LOCs”) were issued to replace letters of credit issued from available capacity under the PNMR Revolving Credit Facility. The letters of credit issued from available capacity under the PNMR Revolving Credit Facility will be surrendered and canceled upon acceptance of the JPM LOCs by the surety companies that issue the reclamation bonds. The letters of credit facilitate the posting of reclamation bonds, which SJCC was required to post in connection with permits relating to the operation of the San Juan mine (Note 11).

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)

Short-term Debt

The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million, both of which mature on October 31, 2020. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. The TNMP Revolving Credit Facility matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At September 30, 2016, the weighted average interest rate was 1.78% for the PNMR Revolving Credit Facility, 1.66% for the PNM Revolving Credit Facility, 1.68% for the PNM New Mexico Credit Facility, and 1.38% for borrowings outstanding under the twelve-month $150.0 million PNMR Term Loan Agreement, which matures in December 2016. Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2016		2015
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	22,400	$	—
PNM New Mexico Credit Facility	20,000		—
TNMP Revolving Credit Facility	—		59,000
PNMR:
PNMR Revolving Credit Facility	163,500		41,600
PNMR Term Loan Agreement	150,000		150,000
	$	355,900	$	250,600

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $36.5 million, $2.5 million, and $0.1 million at September 30, 2016 that reduce the available capacity under their respective revolving credit facilities.

At October 21, 2016, PNMR, PNM, and TNMP had $100.4 million, $373.5 million, and $74.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $44.0 million of availability under the PNM New Mexico Credit Facility. Total availability at October 21, 2016, on a consolidated basis, was $592.8 million for PNMR. As of October 21, 2016, PNM and TNMP had no borrowings from PNMR under intercompany loan agreements. At October 21, 2016, PNMR, PNM, and TNMP had consolidated invested cash of $1.8 million, none, and $0.3 million.

(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 2015 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.

47

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM Plans

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

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	35		$	51		$	—	$	—
Interest cost	7,577			7,064			1,087			1,022			203		190
Expected return on plan assets	(8,854		)	(9,831		)	(1,371		)	(1,403		)	—		—
Amortization of net (gain) loss	3,455			3,705			286			491			64		81
Amortization of prior service cost	(241		)	(241		)	(7		)	(160		)	—		—
Net periodic benefit cost	$	1,937		$	697		$	30		$	1		$	267	$	271
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	105		$	153		$	—	$	—
Interest cost	22,731			21,191			3,260			3,067			609		570
Expected return on plan assets	(26,562		)	(29,492		)	(4,113		)	(4,208		)	—		—
Amortization of net (gain) loss	10,365			11,115			858			1,474			192		243
Amortization of prior service cost	(724		)	(724		)	(22		)	(481		)	—		—
Net periodic benefit cost	$	5,810		$	2,090		$	88		$	5		$	801	$	813

PNM made contributions to its pension plan trust of zero and $30.0 million in the three and nine months ended September 30, 2015 and does not anticipate making any contributions to the pension plan in 2016-2020, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.8% to 5.7%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made contributions to the OPEB trust of $0.8 million and $2.4 million in the three and nine months ended September 30, 2016 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2015. PNM does not expect to make additional contributions to the OPEB trust in 2016 and does not expect to make contributions for 2017-2020.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.2 million in the three and nine months ended September 30, 2016 and $0.4 million and $1.2 million in the three and nine months ended September 30, 2015 and are expected to total $1.5 million during 2016 and $5.9 million for 2017-2020.

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)

TNMP Plans

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

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	—		$	—		$	46		$	62		$	—	$	—
Interest cost	826			761			169			152			10		9
Expected return on plan assets	(986		)	(1,105		)	(122		)	(130		)	—		—
Amortization of net (gain) loss	175			195			(10		)	—			1		1
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost (Income)	$	15		$	(149	)	$	83		$	84		$	11	$	10
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	—		$	—		$	139		$	185		$	—	$	—
Interest cost	2,478			2,282			508			456			30		27
Expected return on plan assets	(2,957		)	(3,315		)	(367		)	(390		)	—		—
Amortization of net (gain) loss	525			586			(30		)	—			1		3
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost (Income)	$	46		$	(447	)	$	250		$	251		$	31	$	30

TNMP made no contribution to its pension trust in 2015 and does not anticipate making any contributions in 2016-2020, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.8% to 5.7%. 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 no contributions to the OPEB trust in the three and nine months ended September 30, 2016 and 2015. TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2016 and $1.4 million for 2017-2020. 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 and nine months ended September 30, 2016 and 2015 and are expected to total $0.1 million during 2016 and $0.4 million in 2017-2020.

(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.

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)

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 2015 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. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. In the first quarter of 2015, PNM recorded $4.3 million, including $3.1 million credited back to PNM’s customers, for its share of the settlement under this process for costs incurred from July 2011 through June 2014. PNM now records estimated claims quarterly. The settlement agreement terminates upon payment of costs incurred through December 31, 2016, unless extended by mutual written agreement.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At September 30, 2016 and December 31, 2015, PNM had a liability for interim storage costs of $12.0 million and $12.2 million included in other deferred credits.

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

On June 8, 2012, the DC Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners 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

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)

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

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. 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 2015 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 $76.8 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 will increase with the installation of SNCR and BDT equipment.

On December 16, 2015, following oral argument, the NMPRC issued a final order regarding SJGS. As provided in that order:

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

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

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)

• 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, (estimated to aggregate approximately $152 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 anticipates developing two resource portfolios in its 2017 IRP to be filed in July 2017, one with SJGS continuing beyond mid-2022 and one where it is shutdown)

• 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

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

At December 31, 2015, PNM estimated the undepreciated net book value of SJGS Units 2 and 3 at December 31, 2017 would be approximately $255.3 million, 50% of which would be recovered over a 20 year period, including a return on the unrecovered amount at PNM’s WACC. At December 31, 2015, PNM recorded a $127.6 million regulatory disallowance to reflect the write-off of the 50% of the estimated December 31, 2017 net book value that will not be recovered. The ultimate amount of the disallowance will be dependent on the actual December 31, 2017 net 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. At December 31, 2015, PNM recorded losses for regulatory disallowances and restructuring costs, aggregating $165.7 million, reflecting the above disallowance, 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”). Additional information about the CSA is discussed under Coal Supply below and in Note 16 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K.

In the three months ended March 31, 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 an expense of $0.8 million that 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 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. In the three months ended September 30, 2016, PNM recorded $5.2 million of additional regulatory disallowances and restructuring costs, including $4.8 million related to a refinement of the estimated liability for coal mine reclamation resulting from the new coal mine reclamation arrangement and $0.4 million from a further revision of estimated December 31, 2017 projected book value of SJGS Units 2 and 3 and the other unrecoverable costs. At September 30, 2016, the carrying value for PNM’s current ownership share of SJGS Units 2 and 3 is comprised of plant in service of $471.6 million and accumulated depreciation and amortization of $201.4 million for a net undepreciated book value of $270.2 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 $141.6 million at September 30, 2016.

On January 14, 2016, NEE filed, with the NM Supreme Court, a Notice of Appeal of the NMPRC’s December 16, 2015 order. On July 22, 2016, NEE filed a brief alleging that the NMPRC’s decision violated NM 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.  PNM’s response brief is due November 2, 2016. In addition, on February 5, 2016, NEE filed, with the NMPRC, a motion for reconsideration of that final order based on developments related to the loan made by NM

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Capital to facilitate the sale of SJCC, which is described under Coal Supply below. NEE alleged the loan is a transaction that, under the New Mexico Public Utility Act, requires prior NMPRC approval. PNM filed its response to NEE’s motion for reconsideration on February 18, 2016. The NEE motion was denied by operation of law because the NMPRC did not act on the motion. On March 31, 2016, NEE filed, with the NMPRC, a complaint 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 to 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 2015 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.

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

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 1-3, which were shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.

PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $90.1 million, including amounts incurred through September 30, 2016 and PNM’s AFUDC. PNM will seek recovery from its ratepayers of all costs that are ultimately incurred. PNM is unable to predict the ultimate outcome of this matter.

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(Unaudited)

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 December 21, 2015, several environmental groups filed a notice of intent to sue the OSM and other federal agencies under the ESA, alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review was not in accordance with applicable law. The environmental review was undertaken as part of the DOI’s review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners.  This review process also required separate environmental impact evaluations under NEPA and culminated in the issuance of a Record of Decision justifying the agency action extending the life of the plant and the adjacent mine.

On April 20, 2016, the same environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for the District of Arizona.  Expanding upon the December 2015 ESA notice, the lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016.  The court granted APS’ motion to intervene in the litigation on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, the Navajo Transitional Energy Company, LLC (“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. 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. Those deadlines will 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 asking the court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court granted the applications to stay the Clean Power Plan pending judicial review of the rule.  The US Supreme Court issued a one-page order that stated, “The EPA rule to have states cut power sector carbon dioxide (CO₂) emissions 32% by 2030 is stayed pending disposition of the applicants’ petitions for review in the United States Court of Appeals for the District of Columbia Circuit.” The vote was 5-4 among the US Supreme Court Justices. The decision means the Clean Power Plan is not in effect and states are not obliged to comply with its requirements. If the rule prevails through the legal challenges, states will be able to resume preparing state plans where they left off and may still have six more months to prepare initial plans and 2.5 years for final plans. The DC Circuit heard oral arguments on September 27, 2016 in the case challenging the Clean Power Plan.  A decision by the DC Circuit is not expected until sometime in 2017. The stay will remain in effect pending US Supreme Court review if such review is sought.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

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. The due date for comments to EPA on the program has been extended to November 1, 2016.

PNM’s review of the new CO₂ emission reductions standards is ongoing and the assessment of its impacts will depend on the outcome of the judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance.

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO₂,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and 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. The next compliance date is in January 2017, when NMED will submit their formal modeling report and recommendations regarding attainment status to EPA. Thereafter, every July, NMED must submit a report to EPA documenting annual SO₂ emissions from SJGS and the associated compliance status.

EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications required under its amended NSR air permit for the installation of SNCRs and installation of BDT equipment to reduce fugitive emissions, including NOx, SO₂ and particulate matter, will assist the plant in complying with the particulate matter NAAQS.

In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 60-70 parts per billion (“ppb”). On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 will use to determine their initial designation recommendations by October 1, 2016. EPA recommends that states and tribes use the three most recent years of quality assured monitoring data available (e.g., 2013 to 2015) to recommend designations. States and tribes may also have preliminary 2016 data that may be used. EPA will 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 their 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.

Four Corners Coal Mine

In 2012, several environmental groups filed a lawsuit in federal district court against the OSM challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners (“Area IV North”). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM took action to cure the defect in its permitting process identified by the court. The owner of the mine appealed to the Tenth Circuit. On December 29, 2015, OSM took action to cure the defect in its permitting process by issuing a revised environmental assessment with a finding of no new significant impact and reissued the permit. On March 30, 2016, the Tenth Circuit vacated and dismissed the appeal on mootness grounds due to OSM’s revised environmental assessment and reapproval of the permit at issue.

WEG v. OSM NEPA Lawsuit

In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012.  In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM.  Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine.  WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008.  WEG alleges various NEPA violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents.  WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans; voiding, reversing, and remanding the various mining modification approvals; enjoining the federal defendants from re-issuing the mining plan approvals for the mines

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 back to OSM for the completion of an EIS. The EIS is to be completed by August 31, 2019. The court ruled that mining operations may continue in the interim and the litigation will be administratively closed. If OSM does not complete the EIS within the time frame provided, the court will order immediate vacatur of the mining plan at issue.  The scope of the EIS will be determined through a public process and is expected to include cumulative and indirect effects of surrounding sources. PNM cannot currently predict the outcome of this matter.

Navajo Nation Environmental Issues

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

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 has been 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 National Pollutant Discharge Elimination System (“NPDES”) permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS has indicated that it does not expect such costs to be material.

Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants.  EPA’s proposal offered numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities,

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(Unaudited)

and non-chemical metal cleaning waste operations.  All proposed alternatives establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. Requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits.

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

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

Based upon the requirements of the final Steam Electric Effluent Guidelines Rule, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. Until a draft NPDES permit is proposed for Four Corners, APS is uncertain what will be required to comply with the finalized effluent limitations.  PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. 

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the 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 gasoline remediation of the site under the supervision of NMED and qualified costs of the work will be eligible for payment through the New Mexico Corrective Action Fund (“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

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(Unaudited)

statutory and regulatory requirements to investigate, minimize, eliminate, or clean up a release. PNM’s work plan and cost estimates for specific groundwater remediation tasks were approved by the Petroleum Storage Tank Bureau. PNM submitted a monitoring plan consisting of a compilation of the data associated with the recent monitoring activities conducted under the CAF to NMED on October 3, 2016. Following review of the data by NMED, PNM, and NMED will develop plans for the next phase of work under the CAF.

Coal Combustion Byproducts Waste Disposal

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

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

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

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

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.

The rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCB rules. The CCB rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in 2016 and will likely be influenced by EPA’s rule. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows. PNM would seek recovery from its ratepayers of all CCB costs that are ultimately incurred.

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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)

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are supplied by SJCC. Through January 31, 2016, SJCC was a wholly owned subsidiary of BHP and supplied processed coal for operation of SJGS under an underground coal sales agreement (“UG-CSA”) that was to expire on December 31, 2017. The parties to the UG-CSA were SJCC, PNM, and Tucson. SJCC holds certain federal, state, and private coal leases. Under the UG-CSA, SJCC was reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and received a return on its investment. In addition to coal delivered to meet the current needs of SJGS, PNM prepaid SJCC for certain coal mined but not yet delivered to the plant site. At September 30, 2016 and December 31, 2015, prepayments for coal, which are included in other current assets, amounted to $54.1 million (including amounts purchased from the existing SJGS participants discussed below) and $49.0 million.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS after the expiration of the UG-CSA. 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”), among NM Capital, The Bank of Tokyo-Mitsubishi UFJ, Ltd. (“BTMU”), as lender, and BTMU, as 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, entered into a Guaranty Agreement, dated as of February 1, 2016, with BTMU (the “Guaranty”). The BTMU Term Loan Agreement and the Guaranty include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio of 65%, and customary events of default consistent with PNMR’s other term loan agreements. In addition, the BTMU Term Loan Agreement has a cross default provision and a change of control provision. The balance outstanding under the BTMU Term Loan Agreement was $107.8 million at September 30, 2016.

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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 Westmoreland Loan is a $125.0 million loan agreement among NM Capital, as lender, WSJ, as borrower, SJCC and its affiliate, as guarantors, BTMU, as Administrative Agent, and MUFG Union Bank, N.A., as Depository Bank. The Westmoreland Loan became effective as of February 1, 2016, and has a maturity date of February 1, 2021. The Westmoreland Loan initially bears interest at a rate of 7.25% plus LIBOR and escalates over time. The Westmoreland Loan has been structured to encourage prepayments and early retirement of the debt. WSJ must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. In addition, the Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. At September 30, 2016, the amount outstanding under the Westmoreland Loan was $110.0 million, after the August 1, 2016 scheduled principal payment of $15.0 million. The next principal payment of $15.0 million plus interest of $2.3 million is due on November 1, 2016. As of October 21, 2016, $17.3 million was held in a 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 was required to post reclamation bonds of $161.6 million with the NMMMD. In April 2016, NMMMD reduced SJCC’s bonding requirements to $118.7 million. In order to facilitate the posting of reclamation bonds by a surety on behalf of SJCC, a Reclamation Bond Agreement (the “Reclamation Bond Agreement”) was entered into by PNMR, Westmoreland, and SJCC with the surety. In connection with the Reclamation Bond Agreement, PNMR used $40.0 million of the available capacity under the PNMR Revolving Credit Facility to support a bank letter of credit arrangement for the benefit of the surety. On July 19, 2016, these reclamation bonds were released by NMMMD upon acceptance of $118.7 million of replacement reclamation bonds from alternate surety companies, which are supported by letters of credit aggregating $30.3 million issued from available capacity under the PNMR Revolving Credit Facility. The Reclamation Bond Agreement was terminated effective August 3, 2016 and the prior letter of credit was surrendered and canceled. On October 21, 2016, PNMR entered into separate letter of credit arrangements with a bank to replace the letters of credit issued from available capacity under the PNMR Revolving Credit Facility. The letters of credit issued from available capacity under the PNMR Revolving Credit Facility will be surrendered and canceled upon acceptance of the replacement letters of credit by the surety companies that issued the reclamation bonds.

Four Corners

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, beginning in July 2016 and expiring in 2031, was entered into with that entity. The BHP subsidiary is to be retained as the mine manager and operator until December 2016. Coal costs are anticipated to increase approximately 40% in the first year of the new contract. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

Coal Mine Reclamation

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

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

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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)

would significantly increase reclamation costs. In addition, design plan changes, updated regulatory expectation, and common mine reclamation practices incorporated into the 2015 SJCC Mine Permit reflect an increase in the 2015 reclamation cost estimate. The impacts of these increases, amounting to $16.5 million, were recorded at December 31, 2015 and were reflected in regulatory disallowances and restructuring costs.

Upon effectiveness of the CSA and the RA, PNM, on behalf of the SJGS owners, coordinated a more detailed coal mine reclamation cost study, which was completed in the third quarter of 2016. To complete the study, PNM was provided access to the mine site and obtained supporting data from Westmoreland, allowing for the 2015 study to be refined with a more extensive engineering analysis. The new reclamation cost estimate reflects the terms of the new reclamation services agreement with Westmoreland and continuation of mining operations through 2053. The study indicates an increase in the reclamation cost estimate. PNM’s share of the increase is $4.8 million, which was recorded at September 30, 2016 and is reflected in regulatory disallowances and restructuring costs in the Condensed Consolidated Statements of Earnings. The current estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new agreement for coal supply.

Based on the 2016 estimates and PNM’s current ownership share of SJGS, PNM’s remaining payments as of September 30, 2016 for mine reclamation, in future dollars, are estimated to be $103.0 million for the surface mines at both SJGS and Four Corners and $129.4 million for the underground mine at SJGS. At September 30, 2016 and December 31, 2015, liabilities, in current dollars, of $41.4 million and $38.8 million for surface mine reclamation and $13.9 million and $11.4 million for underground mine reclamation were recorded in other deferred credits.

Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation liabilities associated with the supply of coal from the San Juan mine. On June 1, 2012, the SJGS owners entered into a trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the UG-CSA. As part of the restructuring of SJGS ownership (see SJGS Ownership Restructuring Matters above), the SJGS owners and PNMR Development negotiated the terms of an amended agreement to fund post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable Reclamation Trust, and periodically deposit funding into the Reclamation Trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels. Based on the existing trust fund balance at September 30, 2016, PNM’s required contributions to its Reclamation Trust fund would be $3.5 million, $4.7 million, and $5.1 million in 2016, 2017, and 2018.

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

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

Continuous Highwall Mining Royalty Rate

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

SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined

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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)

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.

Four Corners Severance Tax Assessment

On May 23, 2013, the New Mexico Taxation and Revenue Department (“NMTRD”) issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners. For procedural reasons, on behalf of the Four Corners co-owners, including PNM, the coal supplier made a partial payment of the assessment and immediately filed a refund claim with respect to that partial payment in August 2013. NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. On June 30, 2015, the court ruled that the assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. NMTRD filed a notice of appeal with the New Mexico Court of Appeals on August 31, 2015. In March 2016, the parties settled this matter. PNM has paid its share of the settlement, which was $0.1 million in addition to amounts previously paid.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with this act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.5 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers. The remaining balance of $13.1 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential retrospective premium assessment per incident for all three units is $38.9 million, with a maximum annual payment limitation of $5.8 million, to be adjusted periodically for inflation.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). A sublimit of $2.25 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium assessments of $5.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to certain policy conditions, sublimits, and exclusions.

Water Supply

Because of New Mexico’s arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast long-term weather patterns. Public policy, local, state and federal regulations, and litigation regarding water could also impact PNM operations. To help mitigate these risks, PNM has secured permanent groundwater rights for the existing plants at Reeves Station, Rio Bravo, Afton, Luna, Lordsburg, and La Luz. Water availability is not an issue for these plants at this time. However, prolonged drought, ESA activities, and a federal lawsuit by the State of Texas (suing the State of New Mexico over water deliveries) could pose a threat of reduced water availability for these plants.

For SJGS, Four Corners, and related mines PNM and APS have secured supplemental water supplies to accommodate the possibility of inadequate precipitation in coming years. To further mitigate the impacts of severe drought, PNM and APS have entered into agreements with the more senior water rights holders (tribes, municipalities, and agricultural interests) in the San Juan

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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)

basin to mutually share the impacts of water shortages with tribes and other water users in the San Juan basin. The agreements spread the burden of shortages over all water users in the basin instead of just having the more junior water rights holders (like APS and PNM) bear the entire impact of shortages. The current agreement expires at the end of 2016. An 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 forty years.

PVNGS Water Supply Litigation

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

San Juan River Adjudication

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

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

Rights-of-Way Matter

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

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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)

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 2 of the 5 allotments at issue based on the Navajo Nation’s fractional interest in the land. PNM’s motion for reconsideration of this ruling was denied. On March 31, 2016, the Tenth Circuit granted PNM’s petition to appeal the December 1, 2015 ruling. On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. Both matters have been consolidated and are stayed while PNM pursues its appeal before the Tenth Circuit. On June 27, 2016, PNM filed its opening brief in the Tenth Circuit. Amicus briefs were filed in support of PNM’s position. On October 5, 2016, the United States, the Navajo Nation, and individual allottees filed their response briefs. After the response briefs were filed, other entities requested leave to file amicus briefs addressing arguments raised in the United States’ response brief. 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 2015 Annual Reports on Form 10-K.

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(Unaudited)

PNM

New Mexico 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. The 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 due to issues identified in PNM’s 2016 renewable energy procurement plan and extended the rate suspension period to July 31, 2016. As ordered by the NMPRC, PNM filed supplemental testimony in the NM 2015 Rate Case demonstrating that PNM’s FPPAC is designed to properly recover its fuel and purchased power expenses. See Renewable Portfolio Standard below. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016, pursuant to the terms of the initial sales-leaseback transactions (Note 6). A subsequent public hearing was held in June 2016. After the close of the April hearing, the NMPRC further extended the rate suspension period through August 31, 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.  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, include:

• The RD proposed a ROE of 9.575% compared to the 10.5% requested by PNM

• The RD proposed 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 are currently $0.8 million per year), 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

• The RD proposed that PNM not recover from retail customers any of the rent expense, which aggregate $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 not recover related property taxes, which are currently $1.5 million per year; 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

• The RD proposed that PNM not recover 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 current rate request

• The RD proposed that $4.5 million of amounts recorded as regulatory assets and deferred charges not be recovered from retail customers

The RD recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing

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(Unaudited)

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 extended the rate suspension period to end on September 30, 2016.  

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

• 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 final order was issued

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

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

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

On September 30, 2016, PNM filed a Notice of Appeal with the NM Supreme Court regarding the final order in the NM 2015 Rate Case. Subsequently, NEE, NMIEC, and ABCWUA filed notices of cross-appeal. On October 26, 2016, PNM filed, with the NM Supreme Court, a statement of issues related to its appeal, 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 final 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 previously leased capacity

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

The court has taken no action with respect to the appeals. 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.

As of September 30, 2016, PNM evaluated the accounting consequences of the final 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 final order will remain in effect. Accordingly, at September 30, 2016, PNM recorded a pre-tax regulatory disallowance of $6.8 million representing 15 months of capital cost recovery of its investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT that the final order disallowed. In addition, PNM recorded a pre-tax regulatory disallowance for $4.5 million of costs reco

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(Unaudited)

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

PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurred and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is reasonably possible that its appeals will be successful, it cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record further pre-tax losses related to any unsuccessful issues. The amounts of any such losses 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 September 30, 2016, the 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 final order; the net book value of such excess amount was $76.9 million, after considering the loss recorded at September 30, 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 $41.7 million, after considering the loss recorded at September 30, 2016

• The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $49.9 million, after considering the loss recorded at September 30, 2016

PNM is unable to predict the outcome of this matter.

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.

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 does 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 RPS procurement costs and customers exempt from RPS procurement costs, the NMPRC again approved the plan in an order issued on February 3, 2016. The NMPRC deferred issues related to capped and exempt customers to PNM’s NM 2015 Rate Case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The NM 2015 Rate Case and show cause proceedings were to examine whether PNM miscalculated the FPPAC factor and base fuel costs in its treatment of renewable energy costs and application of the renewable procurement cost caps and exemptions. On April 28, 2016, PNM filed a motion to stay this proceeding until the issuance of a final order in the NM 2015 Rate Case, based on the fact that the issues addressed in the show cause proceeding were being addressed in the NM 2015 Rate Case. On May 4, 2016, the NMPRC granted PNM’s motion. In the September 28, 2016 final order in the NM 2015 Rate Case, the NMPRC ordered the cost of New Mexico Wind to be recovered through PNM’s renewable rider, rather than the FPPAC, and certain other modifications regarding the accounting for renewable energy in PNM’s FPPAC. These modifications do not

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(Unaudited)

affect the amount of fuel and purchased power or renewable costs that PNM will collect. PNM cannot predict the outcome of the show cause proceeding.

PNM filed its 2017 renewable energy procurement plan on June 1, 2016. The plan meets RPS and diversity requirements for 2017 and 2018 using existing resources and does not propose any significant new procurements. PNM projects that its plan will slightly exceed the RCT in 2017 and will be within the RCT in 2018. PNM has requested a variance from the RCT in 2017 to the extent the NMPRC determines a variance is necessary. A public hearing was held on September 26, 2016. On October 21, 2016, the Hearing Examiner issued a Recommended Decision recommending that the plan be approved as filed and also found that a variance from the RCT is not required. Pursuant to the REA, the NMPRC must enter an order approving or modifying the plan by November 28, 2016. PNM cannot predict the outcome of this matter.

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In PNM’s NM 2015 Rate Case, the NMPRC authorized continuation of the renewable rider.

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

As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM would be required to refund the excess to customers during May through December of the following year. The NMPRC-approved rate was 10.0% when the renewable rider was initially approved. On April 1, 2016, PNM made a compliance filing at the NMPRC showing that its jurisdictional equity return did not exceed 10.5% in 2015.

Energy Efficiency and Load Management

Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s costs to implement approved programs are recovered through a rate rider.

2016 Energy Efficiency Program Application

On April 15, 2016, PNM filed an application for energy efficiency and load management programs to be offered in 2017. The proposed program portfolio consists of ten programs with a total budget of $28.0 million. The application also seeks approval of an incentive of $2.4 million based on target savings of 75 GWh. The actual incentive will be based upon actual savings achieved. An unopposed stipulation settling all issues was filed on September 29, 2016. The stipulation establishes a method to ensure that funding of PNM’s energy efficiency program is equal to 3% of its retail revenues, with an estimated 2017 energy efficiency funding level of $26.0 million, and a sliding scale profit incentive with a base level of 7.1% of program costs if PNM achieves a minimum proscribed level of energy savings and increasing to a maximum of 9.0% depending on actual energy savings achieved above the minimum. A public hearing was held on October 26 and 27, 2016. PNM cannot predict the outcome of this matter.

Energy Efficiency Rulemaking

On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held,

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(Unaudited)

but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

Integrated Resource Plan

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they asserted that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also asked that further proceedings on the IRP be held in abeyance until the conclusion of the then pending SJGS abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that docketed a case to determine whether the IRP complies with applicable NMPRC rules. The order also held the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3. The final 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 will be closed with prejudice within thirty days unless good cause is shown why the docket should remain open. On May 31, 2016, NEE filed a request to hold the protests filed against PNM’s IRP in abeyance or to dismiss those protests without prejudice. PNM responded on June 13, 2016 and requested that the NMPRC dismiss the case with prejudice. The NMPRC has not yet acted on its Notice of Proposed Dismissal or the request filed on May 31, 2016.

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 final 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 June 30, 2015, PNM filed an application for a CCN for a 187 MW gas plant to be located at SJGS. This resource was identified as a replacement resource in PNM’s application to retire SJGS Units 2 and 3. On February 12, 2016, PNM filed a motion to withdraw its application and stated that it would file either a new CCN application for a gas-fueled resource or a report on the status of that application. On May 18, 2016, the NMPRC issued an order granting PNM’s request to withdraw the application and closing the case.

On April 26, 2016, PNM filed an application for an 80 MW gas plant to be located at SJGS. The plant would consist of two40 MW aeroderivative units. PNM had requested a final order from the NMPRC by December 1, 2016 to facilitate a 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. The motion was granted on October 20, 2016. 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. PNM will continue to evaluate its resource needs as part of its ongoing resource planning activities and during the 2017 IRP process in which PNM’s entire 20-year portfolio of supply and demand-side resources will be evaluated in terms of cost and reliability requirements. 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

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(Unaudited)

of the remaining undepreciated investment in existing metering equipment estimated to be approximately $33 million at the date of implementation and the costs of customer education and severance for any affected employees. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. On August 5, 2016, PNM filed a motion to suspend its AMI application so that it could evaluate the effect of the final order in the NM 2015 Rate Case. This motion was approved and PNM must either propose a new procedural schedule or file a motion to withdraw the AMI application by November 28, 2016. 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.

Formula Transmission Rate Case

On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would have resulted in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula.

On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003; and (4) setting the proceeding for hearing and settlement judge procedures. On April 1, 2013, PNM made the required compliance filing. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On August 2, 2013, new rates went into effect, subject to refund. In June 2013, May 2014, and March 2015, PNM made additional filings incorporating final 2012, 2013, and 2014 data into the formula rate request. On March

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(Unaudited)

20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annualized increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates beginning on April 1, 2015, subject to refund. In May 2015, the settlement judge recommended that FERC approve the settlement. On March 17, 2016, FERC approved the settlement. PNM made the refunds required under the settlement in May 2016.

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

As discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2015 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 will serve all of NEC’s load in 2016 at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC is also paying certain third-party transmission costs that it did not pay in 2014 and partially paid in 2015. The PSA and related transmission agreements will terminate on December 31, 2016. In 2017, PNM will serve 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. Revenues from NEC under the PSA were $4.8 million and $6.3 million in the three months ended September 30, 2016 and 2015 and $14.8 million and $19.7 million in the nine months ended September 30, 2016 and 2015.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011. TNMP has completed its mass deployment by installing 242,246 advanced meters over a 5-year period.

The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service is to be borne by opt-out customers through an initial fee and ongoing monthly charge. As approved by the PUCT, TNMP is recovering $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million through a $36.78 monthly fee. These amounts presume up to 1,081 consumers will elect the non-standard meter service, but TNMP has the right to adjust the fees if the number of anticipated consumers differs from that estimate. As of October 21, 2016, 100 customers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

On October 2, 2015, TNMP filed a reconciliation of the costs and savings of its AMS deployment program with the PUCT. Those costs include $71.0 million in capital costs and $18.0 million in operation and maintenance expenses. However, since the deployment was not complete and the total program costs to date were $1.5 million below the original approved forecasts, TNMP did not request a change to its monthly surcharge amount. On January 8, 2016, the PUCT staff recommended that the PUCT approve TNMP’s reconciliation without adjustment and the PUCT accepted that recommendation on March 25, 2016.

Transmission Cost of Service Rates

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

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(Unaudited)

Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 8, 2014	$	25.2	$	4.2
March 16, 2015	27.1		4.4
September 10, 2015	7.0		1.4
March 23, 2016	25.8		4.3
September 8, 2016	9.5		1.8

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor (“EECRF”), which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed mandated savings goals). On May 27, 2016, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2017. The total amount requested is $6.1 million, which includes a performance bonus of $0.8 million based on TNMP’s energy efficiency achievements in the 2015 plan year. On July 27, 2016, TNMP reached a settlement with the PUCT staff and intervenors approving a total request of $6.0 million, which includes a performance bonus of $0.8 million. The settlement was approved by the PUCT on September 8, 2016 and updated rates will become effective on March 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 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, 2016 and 2015, PNM’s regulatory liability was reduced by $7.1 million and $2.0 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: reduced 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; and increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment.

In 2008, fifty percent bonus tax depreciation was enacted as a temporary two-year stimulus measure as part of the Economic Stimulus Act of 2008. Bonus tax depreciation in various forms has been continuously extended since that time, most recently by the Protecting Americans from Tax Hikes Act of 2015. The 2015 act extends and phases-out bonus tax depreciation through 2019. As a result of the net operating loss carryforwards for income tax purposes created by bonus depreciation, and reduced future income taxes payable resulting from New Mexico House Bill 641, certain tax carryforwards are not expected to be utilized before their expiration. In accordance with GAAP, PNMR and PNM have impaired the tax carryforwards which were not expected to be utilized prior to their expiration. During the three months ended March 31, 2015, the impairment of the New Mexico net operating loss carryforward recorded in 2014 was refined, resulting in an additional impairment of $1.0 million, after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. TNMP had no such impairment in 2015. The Company has not recorded any impairments in 2016. The NMPRC’s final order in PNM’s NM 2015 Rate Case (Note 12) 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 the extension of bonus depreciation. The impact, net of federal income taxes, amounts to $2.1 million, which is reflected as a reduction of income tax expense on the Condensed Consolidated Statement of Earnings.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company undertook an analysis of interest income and interest expense applicable to federal income tax matters. The analysis encompassed the impacts of IRS examinations, amended income tax returns, and filings for carrybacks of tax matters to previous taxable years applicable to all years not closed under the IRS rules. As a result of this effort, PNMR received net refunds from the IRS of $6.5 million in the three months ended June 30, 2016. Of the refunds, $2.1 million was recorded as a reduction of interest receivable and $5.1 million was recorded as interest income, which was partially offset by $0.7 million of interest expense. In addition, PNMR incurred $0.9 million in professional fees related to the analysis. Of the net pre-tax impacts aggregating $3.5 million, $2.6 million is reflected in the PNM segment, $0.3 million in the TNMP segment, and $0.6 million in the Corporate and Other segment.

(14) Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In thousands)
Services billings:
PNMR to PNM	$	22,189	$	21,894	$	67,192	$	65,961
PNMR to TNMP	6,593		6,707		20,881		20,366
PNM to TNMP	105		136		347		424
TNMP to PNMR	10		—		30		—
Interest billings:
PNMR to TNMP	13		34		112		167
PNMR to PNM	3		10		8		38
PNM to PNMR	38		24		110		79
Income tax sharing payments:
PNMR to PNM	—		—		—		1,450
PNMR to TNMP	—		—		—		—

(15) Goodwill

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM.

GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. PNMR’s reporting units that have goodwill are PNM and TNMP. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit.

GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity would consider macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity would consider the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity should place more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also should consider positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is

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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)

less than its carrying amount. An entity would evaluate, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis is not required.

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations.

An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units but a quantitative analysis for others. For its annual evaluations performed as of April 1, 2016, PNMR performed quantitative analyses for both the PNM and TNMP reporting units. PNMR utilized a quantitative analysis for the PNM reporting unit and a qualitative analysis for the TNMP reporting unit as of April 1, 2015. For the quantitative analyses, a discounted cash flow methodology was primarily used to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment.

The annual evaluations performed as of April 1, 2016 and 2015 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2016 and 2015 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 25% and 25%. The April 1, 2016 quantitative evaluation indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 32%. Since the April 1, 2016 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill is contained in Note 19 of Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K.

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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 765,000 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 leadership in their business operations

• Supporting the communities in their service territories

Earning Authorized Returns on Regulated Businesses

PNMR’s success in accomplishing its strategic goals is highly dependent on 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, which is critical for PNMR’s ability to achieve its strategic goals. PNMR believes that if the utilities earn their allowed returns, it would be viewed positively by credit rating agencies and would further improve the Company’s ratings, which could lower costs to utility customers. Also, earning allowed returns should result in increased earnings for PNMR, which would lead to increased growth in EPS.

Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K and in Note 12.

State Regulation

New Mexico Rate Case – On August 27, 2015, PNM filed an application with the NMPRC for a general increase in retail electric rates (the “NM 2015 Rate Case”). Key aspects of PNM’s request were:

• An increase in base non-fuel revenues of $121.5 million

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• Based on a future test year (“FTY”) beginning October 1, 2015

• ROE of 10.5%

• Drivers of revenue deficiency

◦Infrastructure investments

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

• 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 revenue decoupling pilot program applicable to residential and small commercial customers

◦Re-allocation of revenue among customer classes

◦A new economic development rate

◦Continuation of PNM’s renewable energy rider

Hearings were held in April and June of 2016. 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, include:

• The RD proposed a ROE of 9.575% compared to the 10.5% requested by PNM

• The RD proposed disallowing recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying leases of portions of PVNGS Unit 2 (Note 6), aggregating 64.1 MW of capacity

• The RD proposed that PNM not recover from retail customers any of the $18.1 million of annual rent expense under leases of capacity, aggregating 114.6 MW, in PVNGS Units 1 and 2 that were extended for eight years beginning January 15, 2015 and 2016 (Note 6);

• The RD also proposed that property taxes on the previously leased assets and the extended leases not be recovered from retail customers; the property taxes aggregate $2.3 million annually

• The RD proposed that PNM not recover 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 current rate request

• The RD proposed that $4.5 million of amounts recorded as regulatory assets and deferred charges not be recovered from retail customers

The RD recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. The RD also proposed changes in the methods of recovering certain costs through PNM’s FPPAC and renewable energy rider. The RD credited retail customers with 100% of the New Mexico jurisdictional portion of revenues from refined coal (a third-party pre-treatment process) at SJGS. The 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 those conclusions. Other parties also filed exceptions to the RD. 

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

• 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 final order was issued

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

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

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

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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, with the NM Supreme Court, a statement of issues related to its appeal, 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 final 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 previously leased capacity

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

The court has taken no action with respect to the appeals. 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.

As of September 30, 2016, PNM evaluated the accounting consequences of the final 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 final 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 final order disallowed and amounts recorded as regulatory assets and deferred charges that the final order disallowed.

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 issued remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record additional pre-tax losses related to any unsuccessful issues. If the appeal is unsuccessful on all issues, the additional losses could aggregate $168.5 million based on the September 30, 2016 book values of PNM’s investments that the final order disallowed, after considering the loss recorded at September 30, 2016.

PNM is unable to 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.

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 advance meter system (Note 12), TNMP has committed to file a general rate case no later than September 1, 2018. TNMP has also committed that it would not file a request for an increase in rates under the PUCT’s rule permitting interim rate adjustments to reflect changes in investments in distribution assets until after the 2018 general rate case.

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FERC Regulation

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

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

On October 29, 2015, PNM and NEC entered into, and filed with FERC, a settlement agreement that includes amendments to the PSA and related contracts. FERC approved the settlement in January 2016. Under the agreement, PNM will serve all of NEC’s load in 2016 at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC is also paying certain third-party transmission costs that it did not pay in 2014 and only partially paid in 2015. The PSA, which contained an expiration date in 2035, will terminate on December 31, 2016. In 2017, PNM will continue to serve 10 MW of NEC’s load under a short-term coordination tariff at a rate lower than provided under the PSA, but higher than prices available under short-term market rates at the time of the settlement. For the nine months ended September 30, 2016 and 2015, revenues were $14.8 million and $19.7 million under the PSA. Although the settlement agreement will negatively impact results of operations in 2016 and 2017, PNM expects to be able to mitigate these impacts through market sales of power that would have been sold to NEC, reductions in fuel and transmission expenses, and other measures. PNM anticipates that, in future general rate cases, assets and costs previously assigned to serve NEC will be reassigned, primarily to retail customers.

Transmission Service Formula Rate Mechanism –PNM filed a request with FERC for an increase in rates charged to transmission customers based on a formula rate mechanism. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which FERC approved on March 17, 2016. The settlement reflects a ROE of 10% and resulted in an annualized increase in rates of $1.3 million above the rates approved in the previous case.

Delivering Above Industry-Average Earnings and Dividend Growth

PNMR’s strategic goal to deliver above industry-average earnings and dividend growth enables investors to realize the value in the Company’s business. PNMR’s current target is seven to eight percent 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%

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Maintaining Solid Investment Grade Credit Ratings

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

Business Focus

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

Reliable and Affordable Power

PNMR and its utilities are aware of the important roles they play in enhancing economic vitality in their 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. Through 2014, both PNM and TNMP ranked in the top quartile nationally for reliability for three out of the previous five years. In 2014, PNM delivered its best reliability performance in the past seven years and TNMP’s reliability was its best in a decade. PNM was again ranked in the electric utility industry top (first) quartile for 2015 despite 2015 being one of the wettest years on record in New Mexico, whereas TNMP’s reliability was ranked in the third quartile as it was more negatively impacted by severe weather events accompanied with record amounts of rain in certain areas of Texas.

Advanced Metering

In September 2011, TNMP began its deployment of advanced meters for homes and businesses across its Texas service area. As of September 30, 2016, TNMP had completed its mass deployment by installing 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. On August 5, 2016, PNM filed a motion to suspend its AMI application so that it could evaluate the effect of the final order in the NM 2015 Rate Case. This motion was approved and PNM must either propose a new procedural schedule or file a motion to withdraw the AMI application by November 28, 2016. PNM cannot predict the outcome of this matter.

Utility Plant Investments

During the 2013 to 2015 period, PNM and TNMP together invested $1,302.4 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. In 2012, PNM announced plans for the 40 MW natural gas-fired La Luz peaking generating station to be located near Belen, New Mexico. Construction began in April 2015 and the facility went into service in December 2015. In addition, on January 15, 2016, PNM completed the $163.3 million acquisition of 64 MW of capacity in PVNGS Unit 2 that had previously been leased to PNM.

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Integrated Resource Plan

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

PNM has begun its process for the 2017 IRP that is to be filed by July 3, 2017. In the NMPRC’s final 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 anticipates developing two resource portfolios in the 2017 IRP, one with SJGS continuing beyond 2022 and one where it is shutdown.

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 2015 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) at 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 (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 (estimated to be approximately $152 million)

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

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

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

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

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

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At December 31, 2015, PNM recorded pre-tax losses aggregating $165.7 million to reflect the write-off of the 50% of the estimated December 31, 2017 net book value of SJGS Units 2 and 3 that will not be recovered, the other unrecoverable costs, and the increase in the estimated liability recorded for coal mine reclamation resulting from the new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”). In the nine months ended September 30, 2016, PNM recorded additional pre-tax losses of $6.0 million resulting from revised estimates of these items. Additional information about the CSA is discussed below and further described under Coal Supply in Note 16 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K and in Note 11.

On January 14, 2016, NEE filed, with the NM Supreme Court, a Notice of Appeal of the NMPRC’s December 16, 2015 final order. On March 31, 2016, NEE filed, with the NMPRC, a complaint 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 to investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. The NMPRC has taken no action on this matter.

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

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

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

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

• Coal supply – The RA became effective contemporaneously with the effectiveness of the new CSA for SJGS. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which occurred on January 31, 2016. In support of the closing of the mine purchase and to facilitate PNM customer savings, NM Capital, a wholly owned subsidiary of PNMR, provided funding of $125.0 million to Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price. NM Capital was able to provide the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement with a commercial bank. PNMR guarantees NM Capital’s obligations to the bank. The Westmoreland Loan has a maturity date of February 1, 2021 and initially bears interest at a rate of 7.25% plus LIBOR and escalates over time. WSJ must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. The Westmoreland Loan has been structured to encourage prepayments and early retirement of the debt. As of October 21, 2016, the balance of the Westmoreland Loan was $110.0 million and $17.3 million was held in a restricted bank account that will be used to make a $15.0 million principal payment on the Westmoreland Loan and interest of $2.3 million, which are due on November 1, 2016.

• Coal mine reclamation – Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation liabilities associated with the supply of coal from the San Juan mine. In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds, 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. PNM estimates that implementation of the BART plan at SJGS discussed

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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 49%, SO₂ by 77%, particulate matter by 78%, and mercury by 98%.

Water Conservation and Solid Waste Reduction

PNM continues its efforts to reduce the amount of fresh water used to make electricity (about 25% more efficient than in 2002). Continued growth in PNM’s fleet of solar, wind, and geothermal energy sources, energy efficiency programs, and innovative uses of gray water and air-cooling technology have contributed to this reduction. Water usage will continue to decline as PNM substitutes less fresh-water-intensive generation resources 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 2015, 20 of the Company’s 23 facilities exceeded a 60% diversion rate, often by a wide margin. 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, 2015, PNM owned 107 MW of utility-scale solar capacity, including 40 MW completed in 2015. The application for a general rate increase discussed above includes recovery of the costs associated with the new 40 MW solar facilities. 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 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 57.3 MW at September 30, 2016. PNM also owns the 500 KW PNM Prosperity Energy Storage Project, which uses advanced batteries to store solar power and dispatch the energy either during high-use periods or when solar production is limited. The project was one of the first combinations of battery storage and PV energy in the nation and involved extensive research and development of advanced grid concepts. The facility was also 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 and future expansion may result in up to 9 MW of generation capacity. PNM also purchases RECs as necessary to meet the RPS.

These renewable resources are key means for PNM to meet the RPS and related regulations that require PNM to achieve prescribed levels of energy sales from renewable sources, if that can be accomplished without exceeding the RCT limit set by the NMPRC. PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM’s 2016 renewable energy procurement plan meets RPS and diversity requirements within the RCT in 2016 and 2017. PNM’s 2017 renewable energy procurement plan meets RPS and diversity requirements for 2017 and 2018 using existing resources and does not propose any significant new procurements. PNM projects that its plan will slightly exceed the RCT in 2017 and has requested a variance from the RCT , but will be within the RCT in 2018. The NMPRC must enter an order approving or modifying the plan by November 28, 2016. 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 continuing to meet their energy needs. PNM’s and TNMP’s energy efficiency and load management portfolios continue to achieve robust results. In 2015, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 79 GWh. This is equivalent to the annual consumption of approximately 10,900 homes in PNM’s service territory. PNM’s load management and energy efficiency programs also help lower peak demand requirements. TNMP’s energy efficiency programs in 2015 resulted in energy savings totaling an estimated 18 GWh. This is equivalent to the annual consumption of approximately 1,660 homes in TNMP’s service territory.

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Customer, Stakeholder, and Community Engagement

The Company strives to deliver a superior customer experience by understanding the dynamic needs of its customers through ongoing market research, identifying and establishing best-in-class services and programs, and proactively communicating and engaging with customers at regional and community levels. Beginning in 2013, PNM refocused its efforts to improve the customer experience through an integrated marketing and communications strategy that encompassed brand repositioning and advertising, customer service improvements, including billing and payment options, and strategic customer and stakeholder engagement. PNM’s focus on these efforts has resulted in increasing scores in the JD Power Electric Utility Residential Customer Satisfaction Study.

Through outreach, collaboration, and various community-oriented programs, PNMR has a demonstrated commitment to build productive relationships with stakeholders, including customers, regulators, legislators, and intervenors.

The PNM Resources Foundation helps nonprofits become more energy efficient through Reduce Your Use grants. In each of 2015 and 2016, the foundation has awarded $0.3 million to support 54 projects in New Mexico to provide shade structure installations, window replacements, and efficient appliance purchases. Since the program’s inception in 2008, Reduce Your Use grants have provided nonprofit agencies in New Mexico with more than $2.1 million of support. In 2014, the PNM Resources Foundation launched a new grant program designed to help nonprofit organizations build more vibrant communities.  In 2015 and 2016, Power Up Grants in the aggregate amount of $0.5 million and $0.5 million were awarded to 34 and 29 nonprofits in New Mexico and Texas for projects ranging from creating community gathering spaces to revitalizing neighborhood parks to building a youth sports field.

PNM

Stakeholder Outreach –PNM continues to expand its key stakeholder outreach to various organizations including business and economic development, environmental and nonprofit organizations, as well as state and local elected officials. Community meetings, one-on-one briefings, and e-newsletter communications are just some of the tools being used to reach a wide array of stakeholders on key PNM issues including environmental commitment, infrastructure investments, price increases, energy savings opportunities, and other timely issues. Recent customer awareness scores have increased regarding PNM’s commitment to the environment, the community, and energy efficiency programs.

Communications –PNM also has expanded its integrated communication efforts, including increased social media efforts, radio, television, newspaper and digital advertising, fact sheets for stakeholders on key PNM issues, e-newsletters, and identification and participation in key stakeholder events. Communication is a major driver for JD Power customer satisfaction scores. PNM’s websites, www.pnm.com and www.PowerforProgress.com, provide 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 websites are 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.

Low-income Customer Outreach –PNM continues its outreach efforts to connect low-income customers with nonprofit community service providers offering support and help with such needs as utility bills, food, clothing, medical programs, services for seniors, and weatherization. In 2015, PNM hosted 38 community events throughout its service territory to assist low-income customers. Furthermore, the PNM Good Neighbor Fund provided $0.4 million of assistance with utility bills to 3,554 families in 2015. In 2015, PNM committed funding of $0.6 million to the PNM Good Neighbor Fund.

TNMP

Community Outreach –In Texas, community outreach is centered first on local relationships, specifically with community leaders, nonprofit organizations, and key customers in areas served by TNMP. Community liaisons serve in each of TNMP’s three business areas, reaching out and ensuring productive lines of communication between TNMP and its key stakeholders.

TNMP maintains long-standing relationships with several key nonprofit organizations, including agencies that support children and families in crisis, food banks, environmental organizations, and educational nonprofits, through employee volunteerism and corporate support. TNMP also actively participates in safety fairs and demonstrations in addition to supporting local chambers of commerce in efforts to build their local economies.

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Energy Efficiency –TNMP’s energy efficiency program discussed above provides unique offers to multiple customer groups, including residential, commercial, government, education, and nonprofit customers. These programs not only enable peak load and consumption reductions, particularly important when severe weather affects Texas’ electric system, but also demonstrate TNMP’s commitment to more than just delivering electricity by partnering with customers to optimize their energy usage. In April 2016, TNMP was recognized by Energy Star for TNMP’s successful energy efficiency efforts. TNMP received the “Partner of the Year Energy Efficiency Delivery Award” for its High-Performance Homes Program.

Economic Factors

PNM –In the nine months ended September 30, 2016, PNM experienced a decrease in weather normalized retail load of 0.6% compared to 2015, primarily due to decreased industrial sales.  PNM has been impacted by a sluggish economy in New Mexico although PNM’s service territory, particularly in the Albuquerque metropolitan area, has recently experienced small business growth. There have been some recent announcements of businesses moving operations into PNM’s service territory, including the selection of a site in New Mexico for a data center by Facebook Inc., and there have been some expansions of existing businesses, particularly in healthcare, education, and professional services. The employment growth recently in the Albuquerque metro area has been improving with growth of 1.2% for the rolling twelve months ended in September 2016. New Mexico overall continues to experience softness that is driven primarily by low oil and natural gas prices. Although PNM does not serve the regions of the state that produce oil and gas, it is anticipated that the impacts of layoffs and the decrease in state royalty revenues will further soften the economies in PNM’s service territory to some degree, particularly in the Albuquerque metropolitan area and Santa Fe, as the state deals with budget shortfalls.

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

TNMP –In the nine months ended September 30, 2016, TNMP’s weather normalized volumetric retail load increased 3.0% compared to 2015 and demand-based load was up 2.9%. 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 that is being impacted by the continued low oil price environment. Employment growth, particularly in Dallas, continues to increase. Since the recent recession, Texas has fared better than the national average in job growth and unemployment although there has been some recent softening in job growth, particularly in the Houston area that appears to be related to lower oil prices.

Results of Operations

Net earnings attributable to PNMR were $92.0 million, or $1.15 per diluted share in the nine months ended September 30, 2016 compared to $107.1 million, or $1.34 per diluted share, in 2015. Among other things, earnings in 2016 benefited from warmer weather in the summer months, including the impacts of rates per KWh being higher in the summer than the rest of the year, increased number of customers, and rate relief at PNM; rate increases and increased load at TNMP; reduced rent expense under the PVNGS leases and plant maintenance costs at PNM; higher interest income; and greater earnings and realized gains on securities held in decommissioning and reclamation trusts compared to the prior year. However, these increases were more than offset by regulatory disallowances, decreased load at PNM in early 2016, lower sales prices for power from PVNGS Unit 3, lower revenue from NEC, lower equity AFUDC, milder weather at TNMP, a 2015 refund under a FERC tariff for gas transportation agreements, and increased depreciation, property tax, interest, and employee related expenses. Additional information on factors impacting results of operation for each segment is discussed under Results of Operations below.

Liquidity and Capital Resources

PNMR has a $300.0 million revolving credit facility and PNM has a $400.0 million revolving credit facility, both of which expire in October 2020. Both facilities provide capacities for short-term borrowing and letters of credit. In addition, PNM has a $50.0 million revolving credit facility, which expires in January 2018, with banks having a significant presence in New Mexico and TNMP has a $75.0 million revolving credit facility, which expires in September 2018. Total availability for PNMR on a consolidated basis was $592.8 million at October 21, 2016. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. PNMR also has intercompany loan agreements with each of its subsidiaries.

The Company projects that its total capital requirements, consisting of construction expenditures and dividends, will total $2,675.0 million for 2016-2020, including amounts expended through September 30, 2016. The construction expenditures include estimated amounts for environmental upgrades at SJGS and Four Corners, 30 MW of new solar capacity to supply power to a new

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data center being constructed by Facebook Inc. (Note 12), and the January 15, 2016 purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases. In addition to internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing in the form of debt refinancing, new debt issuances, and/or new equity in order to fund its capital requirements during the 2016-2020 period. The Company currently believes that its internal cash generation, existing credit arrangements, and access to public and private capital markets will provide sufficient resources to meet the Company’s capital requirements.

RESULTS OF OPERATIONS

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 September 30,							Nine Months Ended September 30,
	2016		2015		Change			2016		2015		Change
	(In millions, except per share amounts)
Net earnings attributable to PNMR	$	54.4	$	61.0	$	(6.6	)	$	92.0	$	107.1	$	(15.1	)
Average diluted common and common equivalent shares	80.1		80.1		—			80.1		80.1		—
Net earnings attributable to PNMR per diluted share	$	0.68	$	0.76	$	(0.08	)	$	1.15	$	1.34	$	(0.19	)

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

	Three Months Ended			Nine Months Ended
	September 30, 2016			September 30, 2016
	(In millions)
PNM	$	(8.3	)	$	(19.7	)
TNMP	0.2			(1.4		)
Corporate and Other	1.6			6.1
Net change	$	(6.6	)	$	(15.1	)

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. In the three and nine months ended September 30, 2016, fuel and purchased power costs passed through the FPPAC were $16.7 million and $78.8 million less than in 2015, which reduced both revenue and cost of energy. The decreases reflect lower coal costs at SJGS beginning in 2016 under the new CSA. See Note 11. In 2015, PNM also was recovering an under-collection of fuel costs that resulted from a prior regulatory proceeding, which amount was fully recovered as of December 31, 2015. See Note 17 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K.

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The following table summarizes the operating results for PNM:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Change			2016			2015			Change
	(In millions)
Electric operating revenues	$	311.3		$	333.4		$	(22.1	)	$	780.2		$	870.8		$	(90.6	)
Cost of energy	88.6			105.7			(17.1		)	222.4			299.3			(76.9		)
Utility margin	222.7			227.7			(5.0		)	557.9			571.5			(13.6		)
Operating expenses	109.3			105.0			4.3			315.0			312.5			2.5
Depreciation and amortization	33.3			29.0			4.3			97.8			86.4			11.4
Operating income	80.1			93.7			(13.6		)	145.1			172.5			(27.4		)
Other income (deductions)	6.5			6.4			0.1			25.9			23.4			2.4
Interest charges	(22.2		)	(19.8		)	(2.4		)	(66.5		)	(59.5		)	(7.0		)
Segment earnings before income taxes	64.3			80.3			(16.0		)	104.5			136.5			(32.0		)
Income (taxes)	(19.3		)	(27.3		)	8.0			(32.1		)	(44.6		)	12.4
Valencia non-controlling interest	(4.0		)	(3.7		)	(0.3		)	(11.0		)	(10.9		)	(0.1		)
Preferred stock dividend requirements	(0.1		)	(0.1		)	—			(0.4		)	(0.4		)	—
Segment earnings	$	40.9		$	49.2		$	(8.3	)	$	60.9		$	80.6		$	(19.7	)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
			Percentage				Percentage
	2016	2015	Change		2016	2015	Change
	(Gigawatt hours, except customers)
Residential	967.9	958.0	1.0	%	2,468.6	2,436.7	1.3	%
Commercial	1,063.5	1,060.1	0.3		2,921.7	2,882.2	1.4
Industrial	223.9	254.7	(12.1	)	658.8	720.3	(8.5	)
Public authority	73.9	72.8	1.5		187.3	182.7	2.5
Economy energy service (1)	197.5	195.8	0.9		610.2	591.8	3.1
Firm-requirements wholesale	100.1	108.3	(7.6	)	324.7	322.9	0.6
Other sales for resale (2)	727.6	515.8	41.1		1,997.4	1,527.4	30.8
	3,354.4	3,165.5	6.0	%	9,168.7	8,664.0	5.8	%
Average retail customers (thousands)	519.0	515.3	0.7	%	518.2	514.4	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 with only a minor impact in utility margin resulting from providing ancillary services.

⁽²⁾ Increase due to more power available for off-system sales, primarily related to SJGS. Ninety percent of the margin from off-system sales, excluding sales from PVNGS Unit 3, is returned to customers through the FPPAC.

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Operating Results – Three months ended September 30, 2016 compared to 2015

The following table summarizes the significant changes to utility margin:

		Three Months Ended September 30, 2016
		Change
Utility margin:		(In millions)
	Customer usage/load –PNM’s weather normalized retail KWh sales decreased 0.4%, but increased for residential and commercial classes, who pay a higher price per KWh; the average number of retail customers increased 0.7%	$	2.6
	Rate relief – Additional revenue due to rate increase approved by the NMPRC on September 28, 2016	2.3
	Weather – Cooler weather in 2016 compared to 2015 resulted in lower sales; cooling degree days were 9.1% lower in 2016	(0.3		)
	Transmission –Higher revenues under formula transmission rates, partly offset by increased cost of third party transmission	0.7
	Wholesale contracts –Primarily lower revenues from NEC (Note 12)	(1.3		)
	Unregulated margin –Lower market prices for PVNGS Unit 3 sales	(3.5		)
	Rate riders –Includes renewable energy and energy efficiency riders, which are offset in operating expenses, depreciation and amortization, and interest charges	(1.8		)
	Net unrealized economic hedges –Primarily related to hedges of PVNGS Unit 3 power sales	(1.9		)
	Other	(1.8		)
	Net Change	$	(5.0	)

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 September 30, 2016
		Change
Operating expenses:		(In millions)
	Regulatory disallowance due to the NMPRC’s September 28, 2016 final order in PNM’s NM 2015 Rate Case (Note 12)	$	11.3
	Regulatory disallowance due to change in estimated write-offs associated with the SJGS BART determination and ownership restructuring (Note 11)	5.2
	Higher pension and OPEB costs	1.5
	Lower labor and outside consulting costs	(1.9		)
	Lower costs associated with rate riders, which are offset in utility margin	(0.5		)
	Lower environmental expenses	(0.6		)
	Lower employee medical costs due to lower claims experience	(0.9		)
	Lower plant maintenance costs	(4.4		)
	Lower rent expense associated with PVNGS leases (Note 6)	(5.6		)
	Other	0.2
	Net Change	$	4.3

		Three Months Ended September 30, 2016
		Change
		(In millions)
Depreciation and amortization:
	Purchase of assets underlying PVNGS Unit 2 leases (Note 6)	$	1.5
	Other additions to utility plant in service, including PNM-owned solar PV facilities and environmental upgrades at SJGS	2.8
	Net Change	$	4.3

Other income (deductions):
	Higher gains on available-for-sale securities in the NDT and coal mine reclamation trusts	$	2.0
	Higher interest income and lower trust expenses related to available-for-sale securities in the NDT and coal mine reclamation trusts	0.4
	Lower equity AFUDC as a result of lower construction spending	(2.5		)
	Other	0.2
	Net Change	$	0.1

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Interest charges:
	Lower debt AFUDC as a result of lower construction spending	$	(1.3	)
	Issuance of $250.0 million of long-term debt on August 11, 2015	(0.9		)
	Other	(0.2		)
	Net Change	$	(2.4	)

Income taxes:
	Decrease due to lower segment earnings before income taxes	$	6.4
	Allowed regulatory recovery of prior year impairment of state net operating loss carryforward (Note 13)	$	2.1
	Other	(0.5		)
	Net Change	$	8.0

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Operating Results – Nine months ended September 30, 2016 compared to 2015

The following table summarizes the significant changes to utility margin:

		Nine Months Ended September 30, 2016
		Change
Utility margin:		(In millions)
	Customer usage/load –PNM’s weather normalized retail KWh sales decreased 0.6%, as increased commercial sales were offset by decreased industrial sales; increased residential sales during the summer months when rates per KWh are higher more than offset decreases in sales from the spring and summer months; the average number of retail customers increased 0.7%	$	1.4
	Rate relief – Additional revenue due to rate increase approved by the NMPRC on September 28, 2016	2.3
	Leap year –Increase in revenue due to additional day in 2016	1.6
	Weather – Warmer summer weather; cooling degree days were higher by 20.9% in the second quarter of 2016, but were lower by 9.1% in the third quarter	2.8
	Transmission –Higher revenues under formula transmission rates and lower cost of third party transmission	2.2
	Wholesale contracts –Primarily lower revenues from NEC (Note 12)	(4.2		)
	Unregulated margin –Lower market prices for PVNGS Unit 3 sales	(9.5		)
	Rate riders –Includes renewable energy and energy efficiency riders, which are offset in operating expenses, depreciation and amortization, and interest charges	(3.1		)
	Net unrealized economic hedges –Primarily related to hedges of PVNGS Unit 3 power sales	(0.9		)
	Gas transportation agreement – 2015 refund under FERC tariff	(4.2		)
	Other	(2.0		)
	Net Change	$	(13.6	)

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

		Nine Months Ended September 30, 2016
		Change
Operating expenses:		(In millions)
	Regulatory disallowance due to the NMPRC’s September 28, 2016 final order in PNM’s NM 2015 Rate Case (Note 12)	$	11.3
	Regulatory disallowance due to change in estimated write-offs associated with the SJGS BART determination and ownership restructuring (Note 11)	5.9
	Higher labor, pension, and OPEB costs	5.4
	Higher property taxes due to increases in utility plant in service	1.2
	Lower rent expense due to the termination of the EIP lease on April 1, 2015	(0.7		)
	Lower environmental expenses	(1.0		)
	2015 regulatory disallowance of rate case expenses resulting from the NMPRC dismissal of the 2014 general rate case	(1.5		)
	Lower plant maintenance costs at SJGS and gas-fired plants, partially offset by increased costs at PVNGS and Four Corners	(1.6		)
	Lower rent expense associated with PVNGS leases (Note 6)	(16.3		)
	Other	(0.2		)
	Net Change	$	2.5

Depreciation and amortization:
	Purchase of assets underlying PVNGS Unit 2 leases (Note 6)	$	3.8
	Other additions to utility plant in service, including PNM-owned solar PV facilities and environmental upgrades at SJGS	7.6
	Net Change	$	11.4

Other income (deductions):
	Higher gains on available-for-sale securities in the NDT and coal mine reclamation trusts	$	3.3
	Interest income from IRS, net of expenses (Note13)	2.9
	Higher interest income and lower trust expenses related to available-for-sale securities in the NDT and coal mine reclamation trusts	1.6
	Sale of substations and associated transmission facilities in 2015	(1.1		)
	Lower equity AFUDC as a result of lower construction spending	(4.3		)
	Net Change	$	2.4

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Interest charges:
	Issuance of $250.0 million of long-term debt on August 11, 2015	$	(5.5	)
	Higher short term debt borrowings	(0.9		)
	Lower debt AFUDC as a result of lower construction spending	(0.9		)
	Other	0.3
	Net Change	$	(7.0	)

		Nine Months Ended September 30, 2016
		Change
Income taxes:		(In millions)
	Decrease due to lower segment earnings before income taxes	$	12.5
	Allowed regulatory recovery of prior year impairment of state net operating loss carryforward (Note 13)	2.1
	Impacts of phased-in reduction in New Mexico corporate income tax rates	(1.3		)
	Other	(0.9		)
	Net Change	$	12.4

TNMP

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

The following table summarizes the operating results for TNMP:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Change			2016			2015			Change
	(In millions)
Electric operating revenues	$	89.1		$	84.0		$	5.1		$	246.5		$	232.4		$	14.1
Cost of energy	20.2			18.5			1.7			60.1			54.6			5.5
Utility margin	68.9			65.4			3.5			186.4			177.7			8.7
Operating expenses	24.2			22.8			1.4			70.3			65.3			5.0
Depreciation and amortization	16.4			15.0			1.4			45.8			42.1			3.7
Operating income	28.4			27.7			0.7			70.3			70.3			—
Other income (deductions)	0.9			0.7			0.2			2.1			2.8			(0.7		)
Interest charges	(7.3		)	(6.9		)	(0.4		)	(22.2		)	(20.6		)	(1.6		)
Segment earnings before income taxes	21.9			21.5			0.4			50.3			52.4			(2.1		)
Income (taxes)	(8.1		)	(7.8		)	(0.3		)	(18.5		)	(19.2		)	0.7
Segment earnings	$	13.9		$	13.7		$	0.2		$	31.8		$	33.2		$	(1.4	)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
			Percentage				Percentage
	2016	2015	Change		2016	2015	Change
	(Gigawatt hours, except consumers)
Residential	1,032.5	993.2	4.0	%	2,314.3	2,338.3	(1.0	)%
Commercial	790.3	767.5	3.0		2,073.6	2,020.3	2.6
Industrial	758.6	694.2	9.3		2,169.9	2,083.4	4.2
Other	24.7	26.5	(6.8	)	73.6	76.1	(3.3	)
	2,606.1	2,481.4	5.0	%	6,631.4	6,518.1	1.7	%
Average retail consumers (thousands)(1)	245.9	242.2	1.5	%	244.9	241.2	1.5	%

⁽¹⁾ TNMP provides transmission and distribution services to REPs that provide electric service to customers in TNMP’s service territories. The number of consumers above represents the customers of these REPs. Under TECA, consumers in Texas have the ability to choose any REP to provide energy.

Operating Results – Three months ended September 30, 2016 compared to 2015

The following table summarizes the significant changes to utility margin:

		Three Months Ended September 30, 2016
		Change
Utility margin:		(In millions)
	Rate relief –Transmission cost of service rate increases in March 2016 and September 2016	$	1.0
	Customer usage/load –3.7% 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; in 2016, the average number of retail customers increased 1.5%	1.3
	Rate riders – Impacts of rate riders, including the AMS surcharge, CTC surcharge, energy efficiency rider, and transmission cost recovery factor, which are offset in operating expenses, depreciation and amortization, and interest charges	1.1
	Energy efficiency program – Higher incentive bonus in 2016	0.1
	Net Change	$	3.5

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

		Three Months Ended September 30, 2016
		Change
Operating expenses:		(In millions)
	Lease abandonments in building consolidation efforts	$	1.0
	Higher labor and outside services	0.3
	Higher rate rider related costs, which are offset in utility margin	0.4
	Increased property taxes due to increases in utility plant in service and higher assessed values	0.3
	Lower property and casualty expense and lower employee medical expense, primarily due to favorable claims experience, partially offset by higher pension expense	(0.9		)
	Other	0.3
	Net Change	$	1.4

Depreciation and amortization:
	Increase primarily due to AMS deployment and other increases in utility plant in service	$	1.4

Other income (deductions):
	Increase primarily due to higher equity AFUDC, partially offset by lower contributions in aid of construction	$	0.2

Interest charges:
	Increase primarily due to the issuance of $60.0 million of long-term debt on February 10, 2016	$	(0.4	)

Income taxes:
	Increase primarily due to higher segment earnings before income taxes and change in the effective tax rate	$	(0.3	)

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Operating Results – Nine months ended September 30, 2016 compared to 2015

The following table summarizes the significant changes to utility margin:

		Nine Months Ended September 30, 2016
		Change
Utility margin:		(In millions)
	Rate relief –Transmission cost of service rate increases in March 2015, September 2015, March 2016, and September 2016	$	3.5
	Customer usage/load –3.0% 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; in 2016, the average number of retail customers increased 1.5%	4.6
	Rate riders – Impacts of rate riders, including the AMS surcharge, CTC surcharge, energy efficiency rider, and transmission cost recovery factor, which are offset in operating expenses, depreciation and amortization, and interest charges	2.9
	Energy efficiency program – Higher incentive bonus in 2016	0.1
	Weather – Milder weather in 2016; heating degree days were 27.3% lower and cooling degree days were 1.9% lower in 2016	(2.4		)
	Net Change	$	8.7

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

		Nine Months Ended September 30, 2016
		Change
Operating expenses:		(In millions)
	Lease abandonments in building consolidation efforts	$	1.0
	Higher labor and outside services	1.7
	Higher rate rider related costs, which are offset in utility margin	0.8
	Increased property taxes due to increases in utility plant in service and higher assessed values	0.8
	Higher employee medical expense primarily due to unfavorable claims experience and higher pension expense	0.6
	Other	0.1
	Net Change	$	5.0

Depreciation and amortization:
	Increase primarily due to AMS deployment and other increases in utility plant in service	$	3.7

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Other income (deductions):
	Decrease primarily due to reduced contributions in aid of construction, partially offset by higher AFUDC and interest income from IRS (Note 13)	$	(0.7	)

		Nine Months Ended September 30, 2016
		Change
Interest charges:		(In millions)
	Increase primarily due to the issuance of $60.0 million of long-term debt on February 10, 2016 and higher short term debt balances	$	(1.6	)

Income taxes:
	Decrease primarily due to lower segment earnings before income taxes	$	0.7

Corporate and Other

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Change			2016			2015			Change
	(In millions)
Total revenues	$	—		$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—			—
Utility margin	—			—			—			—			—			—
Operating expenses	(3.0		)	(3.6		)	0.6			(9.3		)	(11.1		)	1.8
Depreciation and amortization	3.4			3.4			—			10.3			10.5			(0.2		)
Operating income	(0.3		)	0.1			(0.4		)	(1.0		)	0.6			(1.6		)
Other income (deductions)	2.9			(0.5		)	3.4			8.4			(3.0		)	11.4
Interest charges	(2.9		)	(0.8		)	(2.1		)	(8.5		)	(6.6		)	(1.9		)
Segment earnings (loss) before income taxes	(0.4		)	(1.2		)	0.8			(1.2		)	(8.9		)	7.7
Income (taxes) benefit	0.1			(0.7		)	0.8			0.5			2.1			(1.6		)
Segment earnings (loss)	$	(0.3	)	$	(1.9	)	$	1.6		$	(0.7	)	$	(6.8	)	$	6.1

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

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Operating Results – Three months ended September 30, 2016 compared to 2015

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

		Three Months Ended September 30, 2016
		Change
Other income (deductions):		(In millions)
	Interest income on the $125.0 million Westmoreland Loan (Note 11) beginning February 1, 2016	$	3.1
	Other	0.3
	Net Change	$	3.4

Interest charges:
	Issuance of the $125.0 million BTMU Term Loan Agreement on February 1, 2016 (Note 9)	$	(1.2	)
	Issuance of the $150.0 million PNMR 2015 Term Loan Agreement on March 9, 2015	(0.3		)
	Higher short term borrowings	(0.7		)
	Other	0.1
	Net Change	$	(2.1	)

Income taxes:
	Reduction in benefit due to change in segment earnings (loss) before income taxes	$	(0.3	)
	Impairment of wind energy production tax credits in 2015	1.0
	Impairment of New Mexico state net operating loss recorded in 2015	0.1
	Net Change	$	0.8

Operating Results – Nine months ended September 30, 2016 compared to 2015

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

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		Nine Months Ended September 30, 2016
		Change
Other income (deductions):		(In millions)
	Interest income on the $125.0 million Westmoreland Loan (Note 11) beginning February 1, 2016	$	9.0
	Losses recorded in 2015 on items included in other investments related to a former PNMR subsidiary that ceased operations in 2008	1.1
	Interest income from IRS, net of related expenses (Note 13)	0.8
	Other	0.5
	Net Change	$	11.4

		Nine Months Ended September 30, 2016
		Change
Interest charges:		(In millions)
	Issuance of the $125.0 million BTMU Term Loan Agreement on February 1, 2016 (Note 9)	$	(3.4	)
	Higher short term borrowings	(1.8		)
	Issuance of the $150.0 million PNMR 2015 Term Loan Agreement on March 9, 2015	(1.2		)
	Maturity of $118.8 million of long-term debt on May 15, 2015	4.3
	Other	0.2
	Net Change	$	(1.9	)

Income taxes:
	Reduction in benefit due to change in segment earnings (loss) before income taxes	$	(3.0	)
	Impairment of wind energy production tax credits recorded in 2015	1.1
	Impairment of New Mexico state net operating loss recorded in 2015	0.4
	Other	(0.1		)
	Net Change	$	(1.6	)

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR’s cash flows for the nine months ended September 30, 2016 compared to September 30, 2015 are summarized as follows:

	Nine Months Ended September 30,
	2016			2015			Change
	(In millions)
Net cash flows from:
Operating activities	$	321.0		$	335.6		$	(14.6	)
Investing activities	(604.8		)	(387.2		)	(217.6		)
Financing activities	245.4			50.3			195.1
Net change in cash and cash equivalents	$	(38.4	)	$	(1.3	)	$	(37.1	)

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. In addition, contributions to PNMR’s pension and postretirement benefit plans were $30.0 million lower in the nine months ended September 30, 2016 than in 2015 due to a $30.0 million contribution to the PNM pension trust in the nine months ended September 30, 2015 that did not recur in 2016. In addition, PNMR made income tax payments of $0.9 million in the nine months ended September 30, 2016 compared to income tax refunds received of $1.6 million in the nine months ended September 30, 2015.

The changes in PNMR’s cash flows from investing activities relate primarily to an increase of $90.9 million in utility plant additions in the nine months ended September 30, 2016 compared to 2015. Utility plant additions at PNM were $76.2 million higher in the nine months ended September 30, 2016 than in 2015. The PNM increase includes the $163.3 million purchase of

the assets underlying three of the leases for PVNGS Unit 2 (Note 6) on January 15, 2016 and higher nuclear fuel purchases of $2.8 million, offset by decreases in other generation additions of $69.9 million, including decreases of renewable additions of $52.1 million, and lower transmission and distribution additions of $20.0 million. TNMP utility plant additions increased $2.6 million in the nine months ended September 30, 2016 compared to 2015, including increases in transmission and distribution additions of $2.9 million offset by lower AMS additions of $0.3 million. Corporate plant additions increased $12.2 million in the nine months ended September 30, 2016 compared to 2015, including increases related to PNMR computer hardware and software additions of $15.9 million offset by decreases in utility plant additions related to PNMR Development of $3.7 million. Investing activities in 2016 also includes the initial funding of the Westmoreland Loan, net of fees, and the $15.0 million principal received on that loan (Note 11).

The changes in PNMR’s cash flows from financing activities include a $108.3 million increase in net short-term borrowing activity in the nine months ended September 30, 2016 compared to 2015. In 2016, financing activities include a long-term borrowing, net of fees, of $122.5 million under the BTMU Term Loan Agreement and principal repayments of $17.2 million on that loan. NM Capital used the proceeds of the BTMU Term Loan Agreement to provide funds for the Westmoreland Loan. In May 2016, PNM entered into the $175.0 million PNM 2016 Term Loan Agreement and used a portion of the proceeds to prepay $125.0 million outstanding under the PNM Multi-draw Term Loan. In 2016, PNM also participated in the issuance of $146.0 million of its senior unsecured notes, pollution control revenue bonds to refund the same amount of outstanding PCRBs. In 2016, TNMP issued $60.0 million of 3.53% first mortgage bonds and used the funds to reduce short-term debt and intercompany debt. In 2015, long-term borrowings of $150.0 million under the PNMR 2015 Term Loan Agreement were used to repay $118.8 million of 9.25% senior unsecured notes that matured on May 15, 2015 and for general corporate purposes. In 2015, PNM issued $250.0 million aggregate principal amount of its 3.850% Senior Unsecured Notes due 2025. PNM used the proceeds to repay the $175.0 million PNM 2014 Term Loan agreement and to reduce short-term debt. In 2015, PNM also participated in the successful remarketing of $39.3 million of senior unsecured notes, pollution control revenue bonds and had $25.0 million of additional long-term borrowings under the PNM Multi-draw Term Loan.

Financing Activities

See Note 6 of the Notes to Consolidated Financial Statements in the 2015 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. PNMR, PNM, and TNMP are subject to debt-to-capital ratio requirements of less than or equal to 65%.  The Company’s ability to access the credit and capital markets at a reasonable cost is largely dependent upon its:

• Ability to earn a fair return on equity

• Results of operations

• Ability to obtain required regulatory approvals

• Conditions in the financial markets

• Credit ratings

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

As of February 1, 2016, 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 3.51% at September 30, 2016. The principal balance outstanding under the BTMU Term Loan Agreement was $107.8 million at September 30, 2016. 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. See (Note 11).

On May 20, 2016, PNM entered into a $175.0 million term loan agreement (the “PNM 2016 Term Loan Agreement”). The PNM 2016 Term Loan Agreement bears interest at a variable rate, which was 1.15% at September 30, 2016, and has a maturity date of November 17, 2017. PNM used a portion of the proceeds of the PNM 2016 Term Loan Agreement to prepay without penalty the $125.0 million outstanding under the PNM Multi-draw Term Loan, which had a scheduled maturity of June 21, 2016.

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

On October 21, 2016, PNMR entered into a letter of credit arrangement with JPMorgan Chase Bank, N.A. under which letters of credit aggregating $30.3 million (the “JPM LOCs”) were issued to replace letters of credit issued from available capacity under the PNMR Revolving Credit Facility. The letters of credit issued from available capacity under the PNMR Revolving Credit Facility will be surrendered and canceled upon acceptance of the JPM LOCs by the surety companies that issued the reclamation bonds. The letters of credit facilitate the posting of reclamation bonds, which SJCC is required to post in connection with permits relating to the operation of the San Juan mine (Note 11).

At September 30, 2016, interest rates on outstanding borrowings were 1.38% for the PNMR Term Loan Agreement and 1.42% for the PNMR 2015 Term Loan Agreement.

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

• Expanding the electric transmission and distribution systems

• Purchasing nuclear fuel

Projected capital requirements, including amounts expended through September 30, 2016, are:

	2016		2017-2020		Total
	(In millions)
Construction expenditures	$	572.7	$	1,749.2	$	2,321.9
Dividends on PNMR common stock	70.1		280.4		350.5
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	643.3	$	2,031.7	$	2,675.0

The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above include environmental upgrades of $0.8 million at SJGS and $84.8 million at Four Corners, 30 MW of new solar capacity to supply power to a new data center being constructed by Facebook Inc. (Note 12), and the January 2016 purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases for $163.3 million. Expenditures for environmental upgrades are estimated to be $41.2 million in 2016, including amounts expended through September 30, 2016. See Note 11 and Commitments and Contractual Obligations below. The ability of PNMR to pay dividends on its common stock is dependent upon the ability of PNM and TNMP to be able to pay dividends to PNMR. Note 5 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP.

During the nine months ended September 30, 2016, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements, and the additional borrowings described under Financing Activities above.

In addition to the capital requirements for construction expenditures and dividends, the Company has long-term debt that must be paid or refinanced at maturity. As indicated above, the $125.0 million PNM Multi-draw Term Loan was repaid prior to its June 21, 2016 maturity. Note 6 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K contains additional information about the maturities of long-term debt. In addition, NM Capital is required to make quarterly payments of at least $5.0 million under the BTMU Term Loan Agreement. However, NM Capital must also utilize all amounts, le

100

ss 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 $45.1 million on the BTMU Term Loan Agreement in the twelve months ended September 30, 2017. Also, the one-year $150.0 million PNMR Term Loan Agreement matures on December 21, 2016 and $57.0 million of PCRBs are subject to mandatory tender and remarketing on June 1, 2017. PNMR and PNM anticipate that funds to repay the long-term debt maturities and term loans will come from entering into new arrangements similar to the existing agreements, borrowing under their revolving credit facilities, issuance of new long-term debt, or a combination of these sources. The Company has from time to time refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, the Company may refinance other debt issuances or make additional debt repurchases in the future.

Liquidity

PNMR’s liquidity arrangements include the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility both of which expire in October 2020 and the TNMP Revolving Credit Facility that expires in September 2018. The PNMR Revolving Credit Facility has a financing capacity of $300.0 million, the PNM Revolving Credit Facility has a financing capacity of $400.0 million, and the TNMP Revolving Credit Facility has a financing capacity of $75.0 million. PNM also has the $50.0 million PNM New Mexico Credit Facility, which expires 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 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 $79.6 million to $177.5 million during the three months ended September 30, 2016 and from $40.0 million to $177.5 million during the nine months ended September 30, 2016. Borrowings under the PNM Revolving Credit Facility ranged from $10.0 million to $131.0 million during the three months ended September 30, 2016 and zero to $135.0 million during the nine months ended September 30, 2016. Borrowings under the PNM New Mexico Credit Facility ranged from $15.0 million to $35.0 million during the three months ended September 30, 2016 and zero to $50.0 million during the nine months ended September 30, 2016. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $36.0 million during the three months ended September 30, 2016 and zero to $70.0 million during the nine months ended September 30, 2016. At September 30, 2016, the average interest rate was 1.78% for the PNMR Revolving Credit Facility, 1.66% for the PNM Revolving Credit Facility, and 1.68% for the PNM New Mexico Credit Facility. At September 30, 2016, TNMP had no borrowings under the TNMP Revolving Credit Facility or 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. To cover the difference in the amounts and timing of internal cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements. However, if difficult market conditions experienced during the recent recession return, the Company may not be able to access the capital markets or renew credit facilities when they expire. Should that occur, the Company would seek to improve cash flows by reducing capital expenditures and exploring other available alternatives. Also, PNM could consider seeking authorization for the issuance of first mortgage bonds to improve access to the capital markets.

In addition to its internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing to fund its capital requirements during the 2016-2020 period. This could include new debt issuances and/or new equity.

Information concerning the credit ratings for PNMR, PNM, and TNMP was set forth under the heading Liquidity in the MD&A contained in the 2015 Annual Reports on Form 10-K. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade. As of October 21, 2016, ratings on the Company’s securities were as follows:

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	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

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, 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 it is subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.

A summary of liquidity arrangements as of October 21, 2016 is as follows:

	PNMR Separate		PNM Separate		TNMP Separate		PNMR Consolidated
	(In millions)
Financing capacity:
Revolving credit facility	$	300.0	$	400.0	$	75.0	$	775.0
PNM New Mexico Credit Facility	—		50.0		—		50.0
Total financing capacity	$	300.0	$	450.0	$	75.0	$	825.0
Amounts outstanding as of October 21, 2016:
Revolving credit facility	$	163.1	$	24.0	$	—	$	187.1
PNM New Mexico Credit Facility	—		6.0		—		6.0
Letters of credit	36.5		2.5		0.1		39.1
Total short-term debt and letters of credit	199.6		32.5		0.1		232.2
Remaining availability as of October 21, 2016	$	100.4	$	417.5	$	74.9	$	592.8
Invested cash as of October 21, 2016	$	1.5	$	—	$	0.3	$	1.8

The above table includes a $30.3 million of letter of credit support issued under the PNMR Revolving Credit Facility to facilitate the posting of reclamation bonds in connection with the purchase of SJCC by a subsidiary of Westmoreland from BHP. As discussed in Note 11, on October 21, 2016, PNMR entered into separate letter of credit arrangements with a bank under which letters of credit were issued to replace the letters of credit issued under the PNMR Revolving Credit Facility. The letters of credit issued under the PNMR Revolving Credit Facility will be surrendered and canceled upon acceptance of the replacement letters of credit by the surety companies that issued the reclamation bonds. The above table excludes intercompany debt. As of October 21, 2016, PNM and TNMP had no intercompany borrowings from PNMR. The remaining availability under the revolving credit facilities at any point in time varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures.

PNMR 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 and, until April 1, 2015, the EIP transmission line. 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 2015 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 2015 Annual Reports on Form 10-K.

Contingent Provisions of Certain Obligations

As discussed in the 2015 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.

	September 30, 2016		December 31, 2015
PNMR
PNMR common equity	42.1	%	44.0	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	57.6	%	55.7	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	46.0	%	45.3	%
Preferred stock	0.4	%	0.4	%
Long-term debt	53.6	%	54.3	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	58.7	%	59.6	%
Long-term debt	41.3	%	40.4	%
Total capitalization	100.0	%	100.0	%

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OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In 2015, GHG associated with PNM’s interests in its generating plants included approximately 6.4 million metric tons of CO₂, which comprises the vast majority of PNM’s GHG.  By comparison, the total GHG in the United States in 2014, the latest year for which EPA has published this data, were approximately 6.9 billion metric tons, of which approximately 5.5 billion metric tons were CO₂. 

PNM has several programs underway to reduce or offset GHG from its resource portfolio, thereby reducing its exposure to climate change regulation. See Note 12. In 2015, PNM completed construction of 40 MW of utility-scale solar generation, bringing its total owned solar generation capacity to 107 MW. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and, in January 2015, began purchasing the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW. PNM has a 20-year PPA for the output of Lightning Dock Geothermal, which began providing power to PNM in January 2014. The current capacity of the geothermal facility is 4 MW and future expansion may result in up to 9 MW of generation capacity. Additionally, PNM has a customer distributed solar generation program that represented 57.3 MW at September 30, 2016. PNM’s distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 136 GWh. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a budget of $25.8 million for the program year beginning in June 2016. PNM estimates these programs saved approximately 79 GWh of electricity in 2015. Over the next 18 years, PNM projects energy efficiency and load management programs will provide the equivalent of approximately 9,000 GWh of electricity, which will avoid at least 5.5 million metric tons of CO₂ based upon projected emissions from PNM’s system-wide resources. These estimates are subject to change because of the uncertainty of many of the underlying variables, including changes in demand for electricity, and complex relationships between those variables.

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

As of December 31, 2015, approximately 70.6% of PNM’s generating capacity, including resources owned, leased, and under PPAs, all of which is located within the United States, consisted of coal or gas-fired generation that produces GHG. Based on current forecasts, the Company does not expect its output of GHG from existing sources to increase significantly in the near-term. Many factors affect the amount of GHG emitted. For example, if new natural gas-fired generation resources are added to meet increased load as anticipated in PNM’s current IRP, GHG would be incrementally increased. In addition, plant performance could impact the amount of GHG emitted. If PVNGS experienced prolonged outages, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG. As described in Note 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. Although replacement power for these units includes some gas-fired generation, the reduction in GHG from the retirement of the coal-fired generation would be far greater than the increase in GHG from replacement generation.

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

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

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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 the question that it would review to: “Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases.” Specifically, the case dealt with whether EPA’s determination that regulation of GHG from motor vehicles required EPA to regulate stationary sources under the PSD and Title V permitting programs. The petitioners argued that EPA’s determination was unlawful as it violates Congressional intent.

On June 23, 2014, the US Supreme Court issued its opinion on the above case. The US Supreme Court largely 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, EPA had argued that even if it was not required to regulate GHGs under the PSD and Title V programs, the Tailoring Rule was nonetheless justified on the grounds that it was a reasonable interpretation of the CAA. The US Supreme Court rejected this argument. 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. EPA also is requesting comments on establishing a GHG SER level at or above 30,000 tons of CO₂ equivalent per year. Comments on the proposed rule are due on December 2, 2016.

On June 25, 2013, President Obama announced his Climate Action Plan which outlines how his administration plans to cut GHG in the United States, prepare the country for the impacts of climate change, and lead international efforts to combat and prepare for global warming. The plan proposes actions that would lead to the reduction of GHG by 17% below 2005 levels by 2020. The President also issued a Presidential Memorandum to EPA to continue development of the GHG NSPS regulations for electric generators. The Presidential Memorandum establishes a timeline for the reproposal and issuance of a GHG NSPS for new

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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 directs EPA to allow the use of “market-based instruments” and “other regulatory flexibilities” to ensure standards will allow for continued reliance on a range of energy sources and technologies, and that the standards are developed and implemented in a manner that provides for reliable and affordable energy. EPA is to undertake the rulemaking through direct engagement with states, “as they will play a central role in establishing and implementing standards for existing power plants,” and with utility leaders, labor leaders, non-governmental organizations, tribal officials, and other stakeholders.

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

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

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

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

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

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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 are 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 indicates that states may voluntarily adopt the Federal Plan in whole or in part as its state plan. EPA explains in its communications that the proposed Federal Plan will be released in advance of the deadline for submission of state plans to provide regulatory certainty to states that fail to submit 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 indicates that it will choose only one of these approaches in the final Federal Plan. However, the proposed rule will offer both approaches for states to use as models in their own plans. EPA asked for comments on the proposed Federal Plan by January 21, 2016. PNM submitted comments in response.

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, the parties were required to submit a proposed briefing format to the court by January 27, 2016. Briefing on all issues was to be completed by April 22, 2016. Petitioners had asked for bifurcated briefing that would allow the core legal issues to be litigated first and the programmatic issues related to the rule to be litigated later depending on the outcome of the litigation. The court denied that request.

On January 26, 2016, 29 states and state agencies filed a petition to the US Supreme Court asking the court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court granted the applications to stay the Clean Power Plan pending judicial review of the rule.  The US Supreme Court issued a one-page order that stated, “The EPA rule to have states cut power sector carbon dioxide (CO₂) emissions 32% by 2030 is stayed pending disposition of the applicants’ petitions for review in the United States Court of Appeals for the District of Columbia Circuit.” The vote was 5-4 among the US Supreme Court Justices. The decision means the Clean Power Plan is not in effect and states are not obliged to comply with its requirements. If the rule prevails through the legal challenges, states will be able to resume preparing state plans and may still have six more months to prepare initial plans and 2.5 years for final plans (if an extension is granted by EPA). The DC Circuit heard oral arguments on the merits of the states’ case on September 27, 2016. The arguments were made in front of a 10-judge panel. There is no mandatory deadline for the DC Circuit to make a decision on the case and a decision is not expected until sometime in 2017. The stay will remain in effect pending US Supreme Court review if such review is sought.

If the Clean Power Plan prevails, the rule will impact PNM’s existing and future fossil-fueled EGUs. The existing Carbon Pollution Standards covering new sources will also impact PNM’s generation fleet. Impacts could involve investments in additional renewables and energy efficiency programs, efficiency improvements, and/or control technologies at PNM’s fossil-fueled EGUs. Under an emissions rate or mass based trading program, PNM may be required to purchase credits or allowances to comply with New Mexico’s final state plan. There are limited efficiency enhancement measures that may be available to a subset of the existing EGUs; however, such measures would provide only marginal GHG improvements. The only emission control technology for GHG reduction from coal and gas-fired power plants is carbon capture and sequestration, which is not yet a commercially demonstrated technology. Additional GHG control technologies for existing EGUs may become viable in the future. The costs of purchasing carbon credits or allowances, making improvements, or installing new technology could impact the economic viability of some plants. PNM estimates that implementation of the BART plan at SJGS that required the installation of SNCRs on Units 1 and 4 by early 2016, which has been completed, and the retirement of SJGS Units 2 and 3 by the end of 2017 as described in Note 11, should provide a significant step for New Mexico to meet its ultimate compliance with Section 111(d). PNM is unable to predict the impact of this rule on its fossil-fueled generation.

Federal Legislation

Prospects for enactment in Congress of legislation imposing a new or enhanced regulatory program to address climate change are unlikely in 2016.  Instead, EPA is the primary vehicle for GHG regulation in the near future, especially for coal-fired EGUs. The US Supreme Court’s decision to stay the Clean Power Plan does put into question the viability of the rule, but EPA is encouraging states to continue to develop plans for compliance even during the stay. In addition, while there are legislative proposals to limit or block implementation of the Clean Power Plan, enactment of such legislation appears unlikely.

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State and Regional Activity

Pursuant to New Mexico law, each utility must submit an IRP to the NMPRC every three years to evaluate renewable energy, energy efficiency, load management, distributed generation, and conventional supply-side resources on a consistent and comparable basis.  The IRP is required to take into consideration risk and uncertainty of fuel supply, price volatility, and costs of anticipated environmental regulations when evaluating resource options to meet supply needs of the utility’s customers.  The NMPRC requires that New Mexico utilities factor a standardized cost of carbon emissions into their IRPs using prices ranging between $8 and $40 per metric ton of CO₂ emitted and escalating these costs by 2.5% per year.  Under the NMPRC order, each utility must analyze these standardized prices as projected operating costs.  Reflecting the developing nature of this issue, the NMPRC order states that these prices may be changed in the future to account for additional information or changed circumstances.  Although these prices may not reflect the costs that ultimately will be incurred, PNM is required to use these prices for purposes of its IRP.  PNM’s IRP filed with the NMPRC on July 1, 2014 showed that consideration of carbon emissions costs impacted the projected in-service dates of some of the identified resources.  PNM has begun its process for the 2017 IRP that is to be filed by July 1, 2017.

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

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

International Accords

The United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was negotiated at the 1992 United Nations Conference on Environment and Development (informally known as the Earth Summit) and entered into force in March 1994.  The objective of the treaty is to “stabilize greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.”  Parties to the UNFCCC, including the United States, have been meeting annually in Conferences of the Parties (“COP”) to assess progress in meeting the objectives of the UNFCCC.  This assessment process led to the negotiation of the Kyoto Protocol in the mid-1990s.  The Protocol, which was agreed to in 1997 and established legally binding obligations for developed countries to reduce their GHG, was never ratified by the United States.  PNM monitors the proceedings of the UNFCCC, including the annual COP meetings, to determine potential impacts to its business activities.  At the COP meeting in 2011, participating nations, including the United States, agreed to negotiate by 2015 an international agreement involving commitments by all nations to begin reducing carbon emissions by 2020.  On December 12, 2015, the Paris Agreement was finalized during the 2015 COP. The agreement, which was agreed to by more than 190 nations, requires that countries submit Nationally Determined Contributions (“NDCs”). NDCs reflect national targets and actions that arise out of national policies, and elements relating to oversight, guidance and coordination of actions to reduce emissions by all countries.  In November 2014, President Obama announced the United States’ commitment to reduce GHG, on an economy-wide basis, by 26%-28% from 2005 levels by the year 2025. The United States NDC is part of an overall effort by the Obama Administration to have the United States achieve economy-wide reductions of around 80% by 2050.  As part of the process for developing the new global climate agreement, the United States set forth this reduction commitment in its intended NDC.  As part of the Paris Agreement, initial NDCs have been submitted by 189 nations, including the United States and the European Union.  The Paris Agreement will enter into force when at least 55 countries, representing at least 55 percent of total global GHG, have ratified or acceded to it.  To date, the Paris Agreement has been ratified by 75 countries representing more than 58% of global GHG and, as a result, will enter into force on November 4, 2016. 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

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element of its NDC and is based on EPA’s final GHG regulations for new, existing, and modified and reconstructed sources. With the stay of the Clean Power Plan that covers existing sources, it is uncertain how the Obama administration plans to meet its NDC under the Paris Agreement. PNM believes that implementation of the BART plan for SJGS (Note 11) should provide a significant step towards compliance with the Clean Power Plan, should it prevail, or other GHG reduction requirements.

Assessment of Legislative/Regulatory Impacts

The Company has assessed, and continues to assess, the impacts of climate change legislation or regulation on its business.  This assessment is ongoing and future changes arising out of the legislative or regulatory process could impact the assessment significantly.  PNM’s assessment includes assumptions regarding specific GHG limits; the timing of implementation of these limits; the possibility of a market-based trading program, including the associated costs and the availability of emission credits or allowances; the development of emission reduction and/or renewable energy technologies; and provisions for cost containment. Moreover, the assessment assumes various market reactions such as the price of coal and gas and regional plant economics.  These 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.

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.

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Financial Reform Legislation

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Reform Act”), enacted in July 2010, includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading facility. It also includes provisions related to swap transaction reporting and record keeping and may impose margin requirements on swaps that are not centrally cleared. The United States Commodity Futures Trading Commission (“CFTC”) has published final rules defining several key terms related to the act and has set compliance dates for various types of market participants. The Dodd-Frank Reform Act provides exemptions from certain requirements, including an exception to the mandatory clearing and swap facility execution requirements for commercial end-users that use swaps to hedge or mitigate commercial risk.  PNM has elected the end-user exception to the mandatory clearing requirement. PNM expects to be in compliance with the Dodd-Frank Reform Act and related rules within the time frames required by the CFTC. However, as a result of implementing and complying with the Dodd-Frank Reform Act and related rules, PNM’s swap activities could be subject to increased costs, including from higher margin requirements. At this time, PNM cannot predict the ultimate impact the Dodd-Frank Reform Act may have on PNM’s financial condition, results of operations, cash flows, or liquidity.

Other Matters

See Notes 11 and 12 herein and Notes 16 and 17 of the Notes to Consolidated Financial Statements in the 2015 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 September 30, 2016, there have been no significant changes with regard to the critical accounting policies disclosed in PNMR’s, PNM’s, and TNMP’s 2015 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.

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:

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• The ability of PNM and TNMP to recover costs and earn allowed returns in regulated jurisdictions, including the impacts of the NMPRC final order in PNM’s NM 2015 Rate Case and appeals of that order, and the impact on service levels for PNM customers if the ultimate decision does 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 outcome in PNM’s NM 2015 Rate Case, including appeals, 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, mandatory energy efficiency measures, weather, seasonality, alternative sources of power, and other changes in supply and demand, including the failure to maintain or replace customer contracts on favorable terms

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

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

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

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

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

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

• Uncertainty 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 final order in the NM 2015 Rate Case and appeals of that order

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

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

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

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

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

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

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

• The risk that FERC rulemakings may negatively impact the operation of PNM’s transmission system

• The impacts of decreases in the values of marketable securities maintained in trusts to provide for decommissioning, reclamation, pension benefits, and other postretirement benefits, including potential increased volatility resulting from the recent vote by the United Kingdom to exit from the European Union

• 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 2015 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.”

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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 Internet addresses are:

• PNMR: www.pnmresources.com

• PNM: www.pnm.com

• TNMP: www.tnmp.com

In addition to the corporate websites, PNM has a website, www.PowerforProgress.com, dedicated to showing how it balances delivering reliable power at affordable prices and protecting the environment. This website is designed to be a resource for the facts about PNM’s operations and support efforts, including plans for building a sustainable energy future for New Mexico.

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

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

• Quarterly reporting to the Board’s Audit and Finance Committees on these activities

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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 nine months ended September 30, 2016 and the year ended December 31, 2015, the Company had no commodity derivative instruments designated as cash flow hedging instruments.

Commodity contracts, other than those that do not meet the definition of a derivative under GAAP and those derivatives designated as normal purchases and normal sales, are recorded at fair value on the 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.

	Nine Months Ended
	September 30,
	2016			2015
Economic Hedges	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	4,576		$	9,546
Amount realized on contracts delivered during period	(1,294		)	(8,379		)
Changes in fair value	(899		)	7,127
Net mark-to-market change recorded in earnings	(2,193		)	(1,252		)
Net change recorded as regulatory assets and liabilities	(168		)	235
Net fair value at end of period	$	2,215		$	8,529

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 September 30, 2016

	Settlement Dates
	2016			2017
	(In thousands)
Economic hedges
Prices actively quoted	$	—		$	—
Prices provided by other external sources	(271		)	2,486
Prices based on models and other valuations	—			—
Total	$	(271	)	$	2,486

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 nine months ended September 30, 2016, the high, low, and average VaR amounts were $1.3 million, $0.3 million, and $0.6 million. For the year ended December 31, 2015, the high, low, and average VaR amounts were $2.6 million, $0.5 million, and $1.4 million. At September 30, 2016 and December 31, 2015, the VaR amounts for the PNM wholesale portfolio were $0.3 million and $1.2 million.

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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 nine months ended September 30, 2016 or the year ended December 31, 2015.

Credit Risk

The Company is exposed to credit risk from its retail and wholesale customers, as well as the counterparties to derivative instruments. The Company conducts counterparty risk analysis across business segments and uses a credit management process to assess the financial conditions of counterparties. The following table provides information related to credit exposure by the credit worthiness (credit rating) and concentration of credit risk for counterparties to derivative transactions all of which will mature in less than two years.

Schedule of Credit Risk Exposure

September 30, 2016

Rating (1)	Credit Risk Exposure(2)		Number of Counter-parties >10%	Net Exposure of Counter-parties >10%
	(Dollars in thousands)
External ratings:
Investment grade	$	929	—	$	—
Non-investment grade	125		—	—
Split rating	5
Internal ratings:
Investment grade	5,734		1	5,675
Non-investment grade	7		—	—
Total	$	6,800		$	5,675

⁽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 September 30, 2016, PNMR held $0.1 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of September 30, 2016 was $5.7 million.

As discussed in Note 11, PNMR’s subsidiary, NM Capital, entered into the Westmoreland Loan and PNMR has arranged for letters of credit to be issued under the PNMR Revolving Credit Facility to support the acquisition of SJCC by WSJ, a subsidiary of Westmoreland. PNMR is exposed to credit risk under these arrangements in the event of default by WSJ. As of October 21, 2016, remaining required principal payments under the Westmoreland Loan are $15.0 million in 2016, $38.4 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 October 21, 2016, $17.3 million was held in a restricted bank account that will be used solely to make the November 1, 2016 scheduled principal payment of $15.0 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 letter of credit to be remote as discussed in Note 5. Accordingly, PNMR does consider its credit risk under these arrangements to be material.

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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 1.9%, or $47.6 million, if interest rates were to decline by 50 basis points from their levels at September 30, 2016. In general, an increase in fair value would impact earnings and cash flows to the extent not recoverable in rates if all or a portion of debt instruments were acquired in the open market prior to their maturity. At October 21, 2016, PNMR, PNM, and TNMP had short-term debt outstanding of $163.1 million, $24.0 million, and none 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 $6.0 million under the $50.0 million PNM New Mexico Credit Facility at October 21, 2016. The revolving credit facilities, the PNM New Mexico Credit Facility, the $175.0 million PNM 2016 Term Loan Agreement, the $150.0 million PNMR Term Loan Agreement, the $150.0 million PNMR 2015 Term Loan Agreement, and the $125.0 million BTMU Term Loan Agreement bear interest at variable rates. On October 21, 2016, interest rates on borrowings averaged 1.78% for the PNMR Revolving Credit Facility, 1.43% for the PNMR 2015 Term Loan Agreement, 1.38% for the PNMR Term Loan Agreement, 3.51% for the BTMU Term Loan Agreement, 1.15% for the PNM 2016 Term Loan Agreement, 1.66% for the PNM Revolving Credit Facility, and 1.66% for the PNM New Mexico Credit Facility. The Company is exposed to interest rate risk to the extent of future increases in variable interest rates.

The investments held by PNM in trusts for decommissioning and reclamation had an estimated fair value of $271.0 million at September 30, 2016, of which 46.6% 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 September 30, 2016, the decrease in the fair value of the fixed-rate securities would be 3.5%, or $4.4 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 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 and any negative impact resulting from the United Kingdom’s decision to exit the European Union 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 September 30, 2016. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 51.6% of the securities held by the trusts as of September 30, 2016. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $14.0 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 September 30, 2016 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

• Four Corners Coal Mine

• WEG v. OSM NEPA Lawsuit

• Navajo Nation Environmental Issues

• Santa Fe Generating Station

• Continuous Highwall Mining Royalty Rate

• Four Corners Severance Tax Assessment

• PVNGS Water Supply Litigation

• San Juan River Adjudication

• Rights-of-Way Matter

• Navajo Nation Allottee Matters

Note 12

• PNM – New Mexico General Rate Case

• PNM – Renewable Portfolio Standard

• PNM – Renewable Energy Rider

• PNM – Energy Efficiency and Load Management

• PNM – Integrated Resource Plan

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

• PNM – Application for Certificate of Convenience and Necessity

• PNM – Advanced Metering Infrastructure Application

• PNM – Facebook Data Center Project

• PNM – Formula Transmission Rate Case

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

• TNMP – Advanced Meter System Deployment

• TNMP – Transmission Cost of Service Rates

• TNMP – Energy Efficiency

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, 2015.

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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)
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
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:	October 28, 2016	/s/ Joseph D. Tarry
		Joseph D. Tarry
		Vice President, Corporate Controller, and Chief Information Officer
		(Officer duly authorized to sign this report)

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EX-12.1

Exhibit 12.1
PNM RESOURCES, INC. AND SUBSIDIARIES
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Nine Months Ended				Year Ended December 31,
	September 30, 2016				2015				2014				2013				2012			2011
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	97,970			$	117,932			$	117,337			$	118,880			$	125,379		$	122,998
Amortization of debt premium, discount, and expenses	2,839				3,575				4,194				3,716				4,023			3,695
Estimated interest factor of lease rental charges	2,094				3,298				4,686				5,847				5,585			6,665
Preferred dividend requirements of subsidiary	588				784				809				800				769			864
Total Fixed Charges	$	103,491			$	125,589			$	127,026			$	129,243			$	135,756		$	134,222
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes and non-controlling interest	$	153,567			$	46,153			$	200,647			$	175,069			$	175,035		$	321,469
Fixed charges as above	103,491				125,589				127,026				129,243				135,756			134,222
Interest capitalized	(6,045		)		(9,753		)		(6,256		)		(5,209		)		(5,432		)	(2,697		)
Non-controlling interest in earnings of Valencia	(11,037		)		(14,910		)		(14,127		)		(14,521		)		(14,050		)	(14,047		)
Preferred dividend requirements of subsidiary	(588		)		(784		)		(809		)		(800		)		(769		)	(864		)
Earnings Available for Fixed Charges	$	239,388			$	146,295			$	306,481			$	283,782			$	290,540		$	438,083
Ratio of Earnings to Fixed Charges	2.31			1	1.16			2	2.41			3	2.20			3	2.14			3.26			4
1 Earnings from continuing operations before income taxes and non-controlling interest for the nine months ended September 30, 2016 includes a pre-tax loss of $17.2 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 2.48.
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 years ended December 31, 2014 and December 31, 2013 include pre-tax losses of $1.1 million and $12.2 million due to the write-off of regulatory disallowances at PNM. If those losses were excluded, the Ratio of Earnings to Fixed Charges would have been 2.42 for 2014 and 2.29 for 2013.
4  Earnings from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2011 includes pre-tax losses of $21.4 million due to the write-off of regulatory disallowances at PNM and TNMP. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 3.42. In addition, 2011 includes a pre-tax gain on the sale of First Choice of $174.9 million. If that gain was also excluded, the Ratio of Earnings to Fixed Charges would have been 1.96.

EX-12.2

Exhibit 12.2
PUBLIC SERVICE COMPANY OF NEW MEXICO
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Nine Months Ended				Year Ended December 31,
	September 30, 2016				2015				2014				2013				2012			2011
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	68,094			$	84,695			$	79,834			$	79,769			$	82,864		$	75,217
Amortization of debt premium, discount and expenses	1,741				1,978				1,944				1,879				1,818			1,325
Estimated interest factor of lease rental charges	978				1,532				2,541				3,732				3,743			4,139
Total Fixed Charges	$	70,813			$	88,205			$	84,319			$	85,380			$	88,425		$	80,681
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	104,473			$	(13,082	)		$	154,086			$	151,480			$	156,314		$	105,965
Fixed charges as above	70,813				88,205				84,319				85,380				88,425			80,681
Non-controlling interest in earnings of Valencia	(11,037		)		(14,910		)		(14,127		)		(14,521		)		(14,050		)	(14,047		)
Interest capitalized	(4,651		)		(8,530		)		(5,211		)		(4,420		)		(4,314		)	(1,761		)
Earnings Available for Fixed Charges	$	159,598			$	51,683			$	219,067			$	217,919			$	226,375		$	170,838
Ratio of Earnings to Fixed Charges	2.25			1	0.59			2	2.60			3	2.55			4	2.56			2.12			5
1 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the nine months ended September 30, 2016 includes a pre-tax loss of $17.2 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 2.50.
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.
5 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2011 includes a pre-tax loss $17.5 million due to the write-off of regulatory disallowances. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.33.

EX-12.3

Exhibit 12.3
TEXAS-NEW MEXICO POWER COMPANY
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Nine Months Ended			Year Ended December 31,
	September 30, 2016			2015			2014			2013			2012			2011
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	20,806		$	25,875		$	24,941		$	24,481		$	26,233		$	27,914
Amortization of debt premium, discount and expenses	779			1,100			1,195			1,159			1,493			1,679
Estimated interest factor of lease rental charges	894			1,229			1,311			1,241			956			1,202
Total Fixed Charges	$	22,479		$	28,204		$	27,447		$	26,881		$	28,682		$	30,795
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes	$	50,277		$	66,088		$	60,330		$	46,711		$	42,099		$	36,138
Fixed charges as above	22,479			28,204			27,447			26,881			28,682			30,795
Interest capitalized	(539		)	(593		)	(609		)	(361		)	(706		)	(593		)
Earnings Available for Fixed Charges	$	72,217		$	93,699		$	87,168		$	73,231		$	70,075		$	66,340
Ratio of Earnings to Fixed Charges	3.21			3.32			3.18			2.72			2.44			2.15			1
1 Earnings from continuing operations before income taxes for the year ended December 31, 2011 includes a pre-tax loss of $3.9 million due to the write-off of regulatory disallowances. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.28.

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:	October 28, 2016	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			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:	October 28, 2016	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:	October 28, 2016	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:	October 28, 2016	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:	October 28, 2016	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:	October 28, 2016	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 September 30, 2016, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on October 28, 2016 (“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:	October 28, 2016	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			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 September 30, 2016, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on October 28, 2016 (“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:	October 28, 2016	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 September 30, 2016, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on October 28, 2016 (“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:	October 28, 2016	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	9 Months Ended
	Sep. 30, 2016	Oct. 21, 2016
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	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		79,653,624
Public Service Company of New Mexico [Member]
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 [Member]
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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Electric Operating Revenues	$ 400,374	$ 417,433	$ 1,026,726	$ 1,103,187
Operating Expenses:
Cost of energy	108,766	124,255	282,498	353,939
Administrative and general	46,942	46,375	139,214	130,161
Energy production costs	31,460	42,168	112,026	129,627
Regulatory disallowances and restructuring costs	16,451	0	17,225	1,744
Depreciation and amortization	53,017	47,503	153,801	139,013
Transmission and distribution costs	16,056	16,768	49,965	50,123
Taxes other than income taxes	19,611	18,859	57,598	55,093
Total operating expenses	292,303	295,928	812,327	859,700
Operating income	108,071	121,505	214,399	243,487
Other Income and Deductions:
Interest income	4,604	1,151	18,420	4,842
Gains on available-for-sale securities	4,531	2,536	15,380	12,116
Other income	4,884	6,165	13,413	16,844
Other (deductions)	(3,764)	(3,222)	(10,866)	(10,591)
Net other income and deductions	10,255	6,630	36,347	23,211
Interest Charges	32,467	27,528	97,179	86,714
Earnings before Income Taxes	85,859	100,607	153,567	179,984
Income Taxes	27,303	35,752	50,094	61,621
Net Earnings	58,556	64,855	103,473	118,363
(Earnings) Attributable to Valencia Non-controlling Interest	(4,006)	(3,678)	(11,037)	(10,909)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(396)	(396)
Net Earnings Attributable to PNMR	54,418	61,045	92,040	107,058
Net Earnings Available for PNM Common Stock	$ 54,418	$ 61,045	$ 92,040	$ 107,058
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)	$ 0.68	$ 0.77	$ 1.15	$ 1.34
Diluted (dollars per share)	0.68	0.76	1.15	1.34
Dividends Declared per Common Share (dollars per share)	$ 0.22	$ 0.200	$ 0.66	$ 0.600
Public Service Company of New Mexico [Member]
Electric Operating Revenues	$ 311,276	$ 333,437	$ 780,228	$ 870,826
Operating Expenses:
Cost of energy	88,565	105,708	222,376	299,302
Administrative and general	41,370	41,927	122,553	118,450
Energy production costs	31,460	42,168	112,026	129,627
Regulatory disallowances and restructuring costs	16,451	0	17,225	1,744
Depreciation and amortization	33,312	29,042	97,778	86,446
Transmission and distribution costs	9,311	10,478	29,868	31,519
Taxes other than income taxes	10,750	10,404	33,289	31,194
Total operating expenses	231,219	239,727	635,115	698,282
Operating income	80,057	93,710	145,113	172,544
Other Income and Deductions:
Interest income	1,509	1,152	8,549	4,869
Gains on available-for-sale securities	4,531	2,536	15,380	12,116
Other income	3,239	5,369	9,578	13,661
Other (deductions)	(2,790)	(2,616)	(7,653)	(7,230)
Net other income and deductions	6,489	6,441	25,854	23,416
Interest Charges	22,213	19,837	66,494	59,477
Earnings before Income Taxes	64,333	80,314	104,473	136,483
Income Taxes	19,343	27,258	32,131	44,560
Net Earnings	44,990	53,056	72,342	91,923
(Earnings) Attributable to Valencia Non-controlling Interest	(4,006)	(3,678)	(11,037)	(10,909)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(396)	(396)
Net Earnings Attributable to PNMR	40,984	49,378	61,305	81,014
Net Earnings Available for PNM Common Stock	40,852	49,246	60,909	80,618
Texas-New Mexico Power Company [Member]
Electric Operating Revenues	89,098	83,996	246,498	232,361
Operating Expenses:
Cost of energy	20,201	18,547	60,122	54,637
Administrative and general	9,588	9,071	29,382	26,946
Depreciation and amortization	16,354	15,016	45,760	42,065
Transmission and distribution costs	6,745	6,290	20,097	18,604
Taxes other than income taxes	7,851	7,405	20,849	19,782
Total operating expenses	60,739	56,329	176,210	162,034
Operating income	28,359	27,667	70,288	70,327
Other Income and Deductions:
Other income	1,376	774	2,999	3,106
Other (deductions)	(521)	(102)	(860)	(349)
Net other income and deductions	855	672	2,139	2,757
Interest Charges	7,308	6,855	22,150	20,636
Earnings before Income Taxes	21,906	21,484	50,277	52,448
Income Taxes	8,053	7,795	18,460	19,200
Net Earnings Attributable to PNMR	$ 13,853	$ 13,689	$ 31,817	$ 33,248

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Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net Earnings	$ 58,556	$ 64,855	$ 103,473	$ 118,363
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	2,933	(1,862)	1,899	1,882
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(3,101)	(6,090)	(6,180)	(13,714)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience losses recognized as net periodic benefit cost, net of income tax expense (benefit)	839	905	2,517	2,715
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $(172), $276, $509 and $276	269	(428)	(796)	(428)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(79), $0, $(224) and $0	123	0	349	0
Total Other Comprehensive Income (Loss)	1,063	(7,475)	(2,211)	(9,545)
Comprehensive Income	59,619	57,380	101,262	108,818
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,006)	(3,678)	(11,037)	(10,909)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(396)	(396)
Comprehensive Income Attributable to PNMR	55,481	53,570	89,829	97,513
Public Service Company of New Mexico [Member]
Net Earnings	44,990	53,056	72,342	91,923
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	2,933	(1,862)	1,899	1,882
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(3,101)	(6,090)	(6,180)	(13,714)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience losses recognized as net periodic benefit cost, net of income tax expense (benefit)	839	905	2,517	2,715
Fair Value Adjustment for Cash Flow Hedges:
Total Other Comprehensive Income (Loss)	671	(7,047)	(1,764)	(9,117)
Comprehensive Income	45,661	46,009	70,578	82,806
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,006)	(3,678)	(11,037)	(10,909)
Comprehensive Income Attributable to PNMR	$ 41,655	$ 42,331	$ 59,541	$ 71,897

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit	$ (1,877)	$ 1,200	$ (1,216)	$ (1,213)
Reclassification adjustment for (gains) included in net earnings, income tax expense	1,985	3,925	3,955	8,838
Pension liability adjustment, income tax expense (benefit)	(537)	(583)	(1,611)	(1,749)
Change in fair market value, income tax (expense) benefit	(172)	276	509	276
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	(79)	0	(224)	0
Public Service Company of New Mexico [Member]
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit	(1,877)	1,200	(1,216)	(1,213)
Reclassification adjustment for (gains) included in net earnings, income tax expense	1,985	3,925	3,955	8,838
Pension liability adjustment, income tax expense (benefit)	$ (537)	$ (583)	$ (1,611)	$ (1,749)

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Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash Flows From Operating Activities:
Net Earnings	$ 103,473	$ 118,363
Net earnings	92,040	107,058
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	178,137	165,563
Deferred income tax expense	50,302	62,511
Net unrealized (gains) losses on commodity derivatives	2,179	1,251
Realized (gains) on available-for-sale securities	(15,380)	(12,116)
Stock based compensation expense	4,401	3,748
Regulatory disallowances and restructuring costs	17,225	1,744
Other, net	(954)	(4,301)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(1,145)	(23,783)
Materials, supplies, and fuel stock	(4,629)	(3,629)
Other current assets	(11,819)	37,756
Other assets	1,916	12,350
Accounts payable	6,192	1,275
Accrued interest and taxes	20,816	28,233
Other current liabilities	(19,431)	(12,731)
Other liabilities	(10,297)	(40,662)
Net cash flows from operating activities	320,986	335,572
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(502,530)	(411,606)
Proceeds from sales of available-for-sale securities	280,989	166,097
Purchases of available-for-sale securities	(284,706)	(166,268)
Return of principal on PVNGS lessor notes	8,547	21,694
Investment in Westmoreland Loan	(122,250)	0
Principal repayments on Westmoreland Loan	15,000	0
Other, net	179	2,891
Net cash flows from investing activities	(604,771)	(387,192)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	105,300	(3,000)
Long-term borrowings	503,500	463,605
Repayment of long-term debt	(288,157)	(333,066)
Proceeds from stock option exercise	6,668	7,394
Awards of common stock	(14,920)	(18,955)
Dividends paid	(52,967)	(48,188)
Valencia’s transactions with its owner	(12,327)	(12,107)
Other, net	(1,682)	(5,402)
Net cash flows from financing activities	245,415	50,281
Change in Cash and Cash Equivalents	(38,370)	(1,339)
Cash and Cash Equivalents at Beginning of Period	46,051	28,274
Cash and Cash Equivalents at End of Period	7,681	26,935
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	75,537	63,046
Income taxes paid (refunded), net	850	(1,636)
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	30,208	(8,748)
Public Service Company of New Mexico [Member]
Cash Flows From Operating Activities:
Net Earnings	72,342	91,923
Net earnings	61,305	81,014
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	122,344	111,371
Deferred income tax expense	33,175	46,268
Net unrealized (gains) losses on commodity derivatives	2,179	1,251
Realized (gains) on available-for-sale securities	(15,380)	(12,116)
Regulatory disallowances and restructuring costs	17,225	1,744
Other, net	(563)	(5,288)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	8,283	(16,220)
Materials, supplies, and fuel stock	(7,731)	(3,328)
Other current assets	(4,005)	36,707
Other assets	10,117	12,126
Accounts payable	6,819	(794)
Accrued interest and taxes	16,146	22,856
Other current liabilities	(18,908)	(12,099)
Other liabilities	(13,401)	(34,224)
Net cash flows from operating activities	228,642	240,177
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(377,637)	(301,410)
Proceeds from sales of available-for-sale securities	280,989	166,097
Purchases of available-for-sale securities	(284,706)	(166,268)
Return of principal on PVNGS lessor notes	8,547	21,694
Other, net	171	3,051
Net cash flows from investing activities	(372,636)	(276,836)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	42,400	0
Long-term borrowings	321,000	313,605
Repayment of long-term debt	(271,000)	(214,300)
Dividends paid	(4,538)	(46,548)
Equity contribution from parent	28,142	0
Valencia’s transactions with its owner	(12,327)	(12,107)
Other, net	(928)	(4,934)
Net cash flows from financing activities	102,749	35,716
Change in Cash and Cash Equivalents	(41,245)	(943)
Cash and Cash Equivalents at Beginning of Period	43,138	25,480
Cash and Cash Equivalents at End of Period	1,893	24,537
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	53,791	42,680
Income taxes paid (refunded), net	0	(1,450)
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	20,200	(9,933)
Texas-New Mexico Power Company [Member]
Cash Flows From Operating Activities:
Net earnings	31,817	33,248
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	47,055	43,272
Deferred income tax expense	(739)	3,575
Other, net	(391)	(125)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(9,428)	(7,563)
Materials, supplies, and fuel stock	3,102	(301)
Other current assets	(3,570)	2,712
Other assets	(8,415)	(272)
Accounts payable	(6,758)	(210)
Accrued interest and taxes	22,896	19,757
Other current liabilities	(363)	1,033
Other liabilities	399	(5,870)
Net cash flows from operating activities	75,605	89,256
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(93,048)	(90,497)
Net cash flows from investing activities	(93,048)	(90,497)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings, net	(59,000)	(5,000)
Short-term borrowings (repayments) - affiliate, net	(11,800)	25,800
Long-term borrowings	60,000	0
Dividends paid	(17,965)	(19,559)
Equity contribution from parent	50,000	0
Other, net	(775)	0
Net cash flows from financing activities	20,460	1,241
Change in Cash and Cash Equivalents	3,017	0
Cash and Cash Equivalents at Beginning of Period	1	1
Cash and Cash Equivalents at End of Period	3,018	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	15,642	13,308
Income taxes paid (refunded), net	850	545
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$ (10)	$ (216)

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Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 7,681	$ 46,051
Accounts receivable, net of allowance for uncollectible accounts	92,060	98,699
Unbilled revenues	57,705	52,012
Other receivables	17,715	28,590
Current portion of Westmoreland Loan	43,553	0
Materials, supplies, and fuel stock	72,015	67,386
Regulatory assets	7,558	1,070
Commodity derivative instruments	3,949	3,813
Income taxes receivable	6,904	5,845
Other current assets	89,746	82,104
Total current assets	398,886	385,570
Other Property and Investments:
Long-term portion of Westmoreland Loan	66,230	0
Available-for-sale securities	271,035	259,042
Other investments	428	604
Non-utility property	3,404	3,404
Total other property and investments	341,097	263,050
Utility Plant:
Plant in service, held for future use, and to be abandoned	6,842,017	6,307,261
Less accumulated depreciation and amortization	2,312,560	2,058,772
Net plant in service and plant held for future use	4,529,457	4,248,489
Construction work in progress	227,355	204,766
Nuclear fuel, net of accumulated amortization	87,083	82,117
Net utility plant	4,843,895	4,535,372
Deferred Charges and Other Assets:
Regulatory assets	463,016	470,664
Goodwill	278,297	278,297
Commodity derivative instruments	747	2,622
Other deferred charges	77,732	73,753
Total deferred charges and other assets	819,792	825,336
Total assets	6,403,670	6,009,328
Current Liabilities:
Short-term debt	355,900	250,600
Current installments of long-term debt	101,335	124,979
Accounts payable	76,403	100,419
Customer deposits	11,693	12,216
Accrued interest and taxes	80,180	58,306
Regulatory liabilities	6,403	15,591
Commodity derivative instruments	2,423	1,859
Dividends declared	17,656	17,656
Other current liabilities	49,833	59,494
Total current liabilities	701,826	641,120
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	2,207,005	1,966,969
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	935,796	877,393
Regulatory liabilities	468,979	467,413
Asset retirement obligations	119,032	111,895
Accrued pension liability and postretirement benefit cost	63,437	73,097
Commodity derivative instruments	58	0
Other deferred credits	137,686	133,692
Total deferred credits and other liabilities	1,724,988	1,663,490
Total liabilities	4,633,819	4,271,579
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	1,162,599	1,166,465
Accumulated other comprehensive income (loss), net of income taxes	(73,643)	(71,432)
Retained earnings	599,249	559,780
Total stockholders' equity	1,688,205	1,654,813
Non-controlling interest in Valencia	70,117	71,407
Total equity	1,758,322	1,726,220
Total liabilities and stockholders' equity	6,403,670	6,009,328
Public Service Company of New Mexico [Member]
Current Assets:
Cash and cash equivalents	1,893	43,138
Accounts receivable, net of allowance for uncollectible accounts	63,109	78,291
Unbilled revenues	47,450	42,641
Other receivables	15,676	24,725
Affiliate receivables	8,956	15,105
Materials, supplies, and fuel stock	68,208	60,477
Regulatory assets	4,364	0
Commodity derivative instruments	3,949	3,813
Income taxes receivable	15,621	14,577
Other current assets	81,419	74,990
Total current assets	310,645	357,757
Other Property and Investments:
Available-for-sale securities	271,035	259,042
Other investments	197	366
Non-utility property	96	96
Total other property and investments	271,328	259,504
Utility Plant:
Plant in service, held for future use, and to be abandoned	5,303,910	4,833,303
Less accumulated depreciation and amortization	1,785,507	1,569,549
Net plant in service and plant held for future use	3,518,403	3,263,754
Construction work in progress	152,940	172,238
Nuclear fuel, net of accumulated amortization	87,083	82,117
Net utility plant	3,758,426	3,518,109
Deferred Charges and Other Assets:
Regulatory assets	335,025	342,910
Goodwill	51,632	51,632
Commodity derivative instruments	747	2,622
Other deferred charges	71,209	66,810
Total deferred charges and other assets	458,613	463,974
Total assets	4,799,012	4,599,344
Current Liabilities:
Short-term debt	42,400	0
Current installments of long-term debt	56,862	124,979
Accounts payable	59,003	72,386
Affiliate payables	15,082	14,318
Customer deposits	11,693	12,216
Accrued interest and taxes	50,379	33,189
Regulatory liabilities	6,403	15,591
Commodity derivative instruments	2,423	1,859
Dividends declared	132	132
Other current liabilities	31,606	42,251
Total current liabilities	275,983	316,921
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,574,725	1,455,698
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	737,780	696,384
Regulatory liabilities	434,755	434,863
Asset retirement obligations	118,133	111,049
Accrued pension liability and postretirement benefit cost	57,057	66,285
Commodity derivative instruments	58	0
Other deferred credits	117,797	117,275
Total deferred credits and other liabilities	1,465,580	1,425,856
Total liabilities	3,316,288	3,198,475
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	1,236,776
Accumulated other comprehensive income (loss), net of income taxes	(73,240)	(71,476)
Retained earnings	209,400	152,633
Total stockholders' equity	1,401,078	1,317,933
Non-controlling interest in Valencia	70,117	71,407
Total equity	1,471,195	1,389,340
Total liabilities and stockholders' equity	4,799,012	4,599,344
Texas-New Mexico Power Company [Member]
Current Assets:
Cash and cash equivalents	3,018	1
Accounts receivable, net of allowance for uncollectible accounts	28,951	20,408
Unbilled revenues	10,255	9,371
Other receivables	1,129	811
Materials, supplies, and fuel stock	3,807	6,909
Regulatory assets	3,194	1,070
Other current assets	2,167	1,053
Total current assets	52,521	39,623
Other Property and Investments:
Other investments	231	238
Non-utility property	2,240	2,240
Total other property and investments	2,471	2,478
Utility Plant:
Plant in service, held for future use, and to be abandoned	1,342,081	1,285,727
Less accumulated depreciation and amortization	435,245	406,516
Net plant in service and plant held for future use	906,836	879,211
Construction work in progress	45,580	16,561
Net utility plant	952,416	895,772
Deferred Charges and Other Assets:
Regulatory assets	127,991	127,754
Goodwill	226,665	226,665
Other deferred charges	4,776	4,847
Total deferred charges and other assets	359,432	359,266
Total assets	1,366,840	1,297,139
Current Liabilities:
Short-term debt	0	59,000
Short-term debt – affiliate	0	11,800
Accounts payable	9,258	16,006
Affiliate payables	2,346	3,681
Accrued interest and taxes	55,788	32,891
Other current liabilities	3,012	2,044
Total current liabilities	70,404	125,422
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	420,802	361,411
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	232,218	232,791
Regulatory liabilities	34,224	32,550
Asset retirement obligations	739	695
Accrued pension liability and postretirement benefit cost	6,380	6,812
Other deferred credits	4,841	4,078
Total deferred credits and other liabilities	278,402	276,926
Total liabilities	769,608	763,759
Commitments and Contingencies (See Note 11)
Company common stockholders’ equity:
Common stock	64	64
Paid-in-capital	454,166	404,166
Retained earnings	143,002	129,150
Total stockholders' equity	597,232	533,380
Total liabilities and stockholders' equity	$ 1,366,840	$ 1,297,139

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Allowance for uncollectible accounts	$ 1,264	$ 1,397
Accumulated depreciation, nuclear fuel	$ 50,623	$ 44,455
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 [Member]
Allowance for uncollectible accounts	$ 1,264	$ 1,397
Accumulated depreciation, nuclear fuel	$ 50,623	$ 44,455
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 [Member]
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 - 9 months ended Sep. 30, 2016 - USD ($) $ in Thousands	Total	Total PNMR Common Stockholders’ Equity [Member]	Common Stock [Member]	AOCI [Member]	Retained Earnings [Member]	Non-controlling Interest in Valencia [Member]	Public Service Company of New Mexico [Member]	Public Service Company of New Mexico [Member] Total PNMR Common Stockholders’ Equity [Member]	Public Service Company of New Mexico [Member] Common Stock [Member]	Public Service Company of New Mexico [Member] AOCI [Member]	Public Service Company of New Mexico [Member] Retained Earnings [Member]	Public Service Company of New Mexico [Member] Non-controlling Interest in Valencia [Member]	Texas-New Mexico Power Company [Member]	Texas-New Mexico Power Company [Member] Common Stock [Member]	Texas-New Mexico Power Company [Member] Paid-in Capital [Member]	Texas-New Mexico Power Company [Member] Retained Earnings [Member]
Beginning balance at Dec. 31, 2015	$ 1,726,220	$ 1,654,813	$ 1,166,465	$ (71,432)	$ 559,780	$ 71,407	$ 1,389,340	$ 1,317,933	$ 1,236,776	$ (71,476)	$ 152,633	$ 71,407
Beginning balance TNMP at Dec. 31, 2015	1,654,813						1,317,933						$ 533,380	$ 64	$ 404,166	$ 129,150
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Earnings	103,473	92,436			92,436	11,037	72,342	61,305		0	61,305	11,037
Net earnings	92,040						61,305						31,817			31,817
Total other comprehensive income (loss)	(2,211)	(2,211)		(2,211)			(1,764)	(1,764)		(1,764)	0
Subsidiary preferred stock dividends	(396)	(396)			(396)
Dividends declared on preferred stock							(396)	(396)		0	(396)
Equity contribution from parent							28,142	28,142	28,142				50,000	0	50,000	0
Dividends declared on common stock	(52,571)	(52,571)			(52,571)		(4,142)	(4,142)		0	(4,142)		(17,965)			(17,965)
Proceeds from stock option exercise	6,668	6,668	6,668
Awards of common stock	(14,920)	(14,920)	(14,920)
Excess tax (shortfall) from stock-based payment arrangements	(15)	(15)	(15)
Stock based compensation expense	4,401	4,401	4,401
Valencia’s transactions with its owner	(12,327)					(12,327)	(12,327)					(12,327)
Ending balance at Sep. 30, 2016	1,758,322	$ 1,688,205	$ 1,162,599	$ (73,643)	$ 599,249	$ 70,117	1,471,195	$ 1,401,078	$ 1,264,918	$ (73,240)	$ 209,400	$ 70,117
Ending balance TNMP at Sep. 30, 2016	$ 1,688,205						$ 1,401,078						$ 597,232	$ 64	$ 454,166	$ 143,002

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Significant Accounting Policies and Responsibility for Financial Statements

9 Months Ended

Sep. 30, 2016

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 September 30, 2016 and December 31, 2015, the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2016 and 2015, and cash flows for the nine months ended September 30, 2016 and 2015. 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 2015 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2016 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 2015 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.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.22 per share in July 2016 and $0.20 in July 2015, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. The Board declared dividends on common stock considered to be for the third quarter of $0.22 per share in September 2016 and $0.20 per share in September 2015, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

In the nine months ended September 30, 2016, PNMR made equity contributions of $28.1 million to PNM and $50.0 million to TNMP. PNM declared and paid cash dividends on common stock to PNMR of $4.1 million and $46.2 million in the nine months ended September 30, 2016 and 2015. TNMP declared and paid cash dividends on common stock to PNMR of $18.0 million and $19.6 million in the nine months ended September 30, 2016 and 2015.

New Accounting Pronouncements

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

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

In May 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. When it becomes effective, the new standard will replace most existing revenue recognition guidance in GAAP. In August 2015, the FASB issued a one-year deferral in the effective date. Since the issuance of ASU No. 2014-09, the FASB also has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. The Company must adopt ASU 2014-09 beginning on January 1, 2018. Early adoption would be permitted beginning January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method although it is unlikely the Company would elect to early adopt the new standard. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures, but has not determined the effect of the standard on its financial reporting.

Accounting Standards Update 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

In August 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company anticipates adopting this standard as of December 31, 2016. The Company is 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 2016-01 – 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. The new standard will be effective for the Company beginning on January 1, 2018. Early adoption of the standard is permitted. The Company is in the process of analyzing the impacts of this new standard.

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. The new standard will be effective for the Company beginning on January 1, 2019. Early adoption of the standard is permitted. At adoption of the ASU, leases will be recognized and measured as of the earliest period presented using a modified retrospective approach. The Company is in the process of analyzing the impacts of this new standard.

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

In March 2016, the FASB issued ASU No. 2016-09. The ASU simplifies several aspects of the accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Currently, tax benefits resulting from deductions in excess of compensation cost on vested restricted stock and performance awards and on exercised stock options (“excess tax benefits”) are recorded to equity provided these benefits reduce taxes payable. Tax deficiencies resulting from deductions related to awards, which are below realized compensation cost upon vesting and on canceled stock options are recorded to equity. The Company has not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. Upon implementation of the new standard, the Company will record a cumulative effect adjustment to recognize excess tax benefits that have not been recorded due to the Company’s net operating loss. Subsequent to implementation, all excess tax benefits and deficiencies will be recorded to tax expense on the Condensed Consolidated Income Statements and classified as cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. The Company continues its process of analyzing the impacts of this new standard, but does not believe there will be any retrospective impacts to its financial statements. The Company anticipates adopting the new standard upon its required effective date of January 1, 2017.

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. The new standard is effective for the Company beginning on January 1, 2018.  Early adoption is permitted including adoption in an interim period.   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.

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Earnings Per Share

9 Months Ended

Sep. 30, 2016

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				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	54,418	$	61,045	$	92,040	$	107,058
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	96		100		99		103
Average Shares – Basic	79,750		79,754		79,753		79,757
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	367		362		377		377
Average Shares – Diluted	80,117		80,116		80,130		80,134
Net Earnings Per Share of Common Stock:
Basic	$	0.68	$	0.77	$	1.15	$	1.34
Diluted	$	0.68	$	0.76	$	1.15	$	1.34

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Segment Information

9 Months Ended

Sep. 30, 2016

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 provides generation service to firm-requirements wholesale customers and sells electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM’s jurisdictional capacity, as well as the capacity from PVNGS Unit 3, which currently is not included in retail rates (Note 11). FERC has jurisdiction over wholesale power and transmission rates.

TNMP

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

Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and investments, as well as 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 September 30, 2016
Electric operating revenues	$	311,276		$	89,098		$	—		$	400,374
Cost of energy	88,565			20,201			—			108,766
Utility margin	222,711			68,897			—			291,608
Other operating expenses	109,342			24,184			(3,006		)	130,520
Depreciation and amortization	33,312			16,354			3,351			53,017
Operating income (loss)	80,057			28,359			(345		)	108,071
Interest income	1,509			—			3,095			4,604
Other income (deductions)	4,980			855			(184		)	5,651
Interest charges	(22,213		)	(7,308		)	(2,946		)	(32,467		)
Segment earnings (loss) before income taxes	64,333			21,906			(380		)	85,859
Income taxes (benefit)	19,343			8,053			(93		)	27,303
Segment earnings (loss)	44,990			13,853			(287		)	58,556
Valencia non-controlling interest	(4,006		)	—			—			(4,006		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	40,852		$	13,853		$	(287	)	$	54,418
Nine Months Ended September 30, 2016
Electric operating revenues	$	780,228		$	246,498		$	—		$	1,026,726
Cost of energy	222,376			60,122			—			282,498
Utility margin	557,852			186,376			—			744,228
Other operating expenses	314,961			70,328			(9,261		)	376,028
Depreciation and amortization	97,778			45,760			10,263			153,801
Operating income (loss)	145,113			70,288			(1,002		)	214,399
Interest income	8,549			—			9,871			18,420
Other income (deductions)	17,305			2,139			(1,517		)	17,927
Interest charges	(66,494		)	(22,150		)	(8,535		)	(97,179		)
Segment earnings (loss) before income taxes	104,473			50,277			(1,183		)	153,567
Income taxes (benefit)	32,131			18,460			(497		)	50,094
Segment earnings (loss)	72,342			31,817			(686		)	103,473
Valencia non-controlling interest	(11,037		)	—			—			(11,037		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	60,909		$	31,817		$	(686	)	$	92,040
At September 30, 2016:
Total Assets	$	4,799,012		$	1,366,840		$	237,818		$	6,403,670
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2015
Electric operating revenues	$	333,437		$	83,996		$	—		$	417,433
Cost of energy	105,708			18,547			—			124,255
Utility margin	227,729			65,449			—			293,178
Other operating expenses	104,977			22,766			(3,573		)	124,170
Depreciation and amortization	29,042			15,016			3,445			47,503
Operating income	93,710			27,667			128			121,505
Interest income	1,152			—			(1		)	1,151
Other income (deductions)	5,289			672			(482		)	5,479
Interest charges	(19,837		)	(6,855		)	(836		)	(27,528		)
Segment earnings (loss) before income taxes	80,314			21,484			(1,191		)	100,607
Income taxes (benefit)	27,258			7,795			699			35,752
Segment earnings (loss)	53,056			13,689			(1,890		)	64,855
Valencia non-controlling interest	(3,678		)	—			—			(3,678		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	49,246		$	13,689		$	(1,890	)	$	61,045
Nine Months Ended September 30, 2015
Electric operating revenues	$	870,826		$	232,361		$	—		$	1,103,187
Cost of energy	299,302			54,637			—			353,939
Utility margin	571,524			177,724			—			749,248
Other operating expenses	312,534			65,332			(11,118		)	366,748
Depreciation and amortization	86,446			42,065			10,502			139,013
Operating income	172,544			70,327			616			243,487
Interest income	4,869			—			(27		)	4,842
Other income (deductions)	18,547			2,757			(2,935		)	18,369
Interest charges	(59,477		)	(20,636		)	(6,601		)	(86,714		)
Segment earnings (loss) before income taxes	136,483			52,448			(8,947		)	179,984
Income taxes (benefit)	44,560			19,200			(2,139		)	61,621
Segment earnings (loss)	91,923			33,248			(6,808		)	118,363
Valencia non-controlling interest	(10,909		)	—			—			(10,909		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	80,618		$	33,248		$	(6,808	)	$	107,058
At September 30, 2015:
Total Assets	$	4,615,442		$	1,282,766		$	114,374		$	6,012,582
Goodwill	$	51,632		$	226,665		$	—		$	278,297

At December 31, 2015, the Company adopted ASU 2015-03 – Interest – Imputation of Interest (Subtopic 835-30) and ASU 2015-17, Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes, which require that debt issuance costs be reflected as a direct reduction of the related debt liability, except for arrangements such as the Company’s revolving credit facilities, and eliminated the requirement to classify deferred tax assets and liabilities as non-current or current. The Company applied the updates retrospectively to make all periods comparable. As a result, amounts previously reported as total assets at September 30, 2015 above have been reduced to reflect the reclassifications aggregating $40.3 million for PNMR, $22.1 million for PNM, and $10.4 million for TNMP.

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Accumulated Other Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2016 and 2015 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, 2015	$	17,346		$	(88,822	)	$	(71,476	)	$	44		$	(71,432	)
Amounts reclassified from AOCI (pre-tax)	(10,135		)	4,128			(6,007		)	573			(5,434		)
Income tax impact of amounts reclassified	3,955			(1,611		)	2,344			(224		)	2,120
Other OCI changes (pre-tax)	3,115			—			3,115			(1,305		)	1,810
Income tax impact of other OCI changes	(1,216		)	—			(1,216		)	509			(707		)
Net change after income taxes	(4,281		)	2,517			(1,764		)	(447		)	(2,211		)
Balance at September 30, 2016	$	13,065		$	(86,305	)	$	(73,240	)	$	(403	)	$	(73,643	)

Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—		$	(61,755	)
Amounts reclassified from AOCI (pre-tax)	(22,552		)	4,464			(18,088		)	—			(18,088		)
Income tax impact of amounts reclassified	8,838			(1,749		)	7,089			—			7,089
Other OCI changes (pre-tax)	3,095			—			3,095			(704		)	2,391
Income tax impact of other OCI changes	(1,213		)	—			(1,213		)	276			(937		)
Net change after income taxes	(11,832		)	2,715			(9,117		)	(428		)	(9,545		)
Balance at September 30, 2015	$	16,176		$	(87,048	)	$	(70,872	)	$	(428	)	$	(71,300	)

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 nine months ended September 30, 2016 and 2015, 24.3% and 22.4% of the pension amounts reclassified were capitalized into construction work in process and 2.5% and 2.5% 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

9 Months Ended

Sep. 30, 2016

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 2015 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 operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and nine months ended September 30, 2016, PNM paid $4.9 million and $14.5 million for fixed charges and $0.5 million and $1.1 million for variable charges. For the three and nine months ended September 30, 2015, PNM paid $4.9 million and $14.5 million for fixed charges and $0.3 million and $0.9 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM 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. 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(In thousands)
Operating revenues	$	5,356		$	5,182		$	15,541		$	15,337
Operating expenses	(1,350		)	(1,504		)	(4,504		)	(4,428		)
Earnings attributable to non-controlling interest	$	4,006		$	3,678		$	11,037		$	10,909

Financial Position

	September 30,		December 31,
	2016		2015
	(In thousands)
Current assets	$	3,506	$	2,588
Net property, plant, and equipment	67,656		69,784
Total assets	71,162		72,372
Current liabilities	1,045		965
Owners’ equity – non-controlling interest	$	70,117	$	71,407

During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the VIE. The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process was initiated since the parties failed to reach agreement on fair market value within 60 days. Under the PPA, results of the appraisal process established the purchase price after which PNM was to determine in its sole discretion whether or not to exercise its option to purchase the 50% interest. The PPA also provides that the purchase price may be adjusted to reflect the period between the determination of the purchase price and the closing. The appraisal process determined the purchase price as of October 8, 2013 to be $85.0 million, prior to any adjustment to reflect the period through the closing date. Approval of the NMPRC and FERC would be required, which process could take up to 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. The owner of Valencia submitted a counter-proposal to PNM in April 2015 and the parties are continuing to have periodic discussions. PNM cannot predict if it will reach agreement with the owner of Valencia, if required regulatory and other approvals will be received, or if the purchase will be completed.

PVNGS Leases

PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which initially were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. At January 15, 2015, the four Unit 1 leases were extended. At January 15, 2016, one of the Unit 2 leases was extended and PNM exercised its fair market value options to purchase the assets underlying the other three Unit 2 leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K and Note 6 for additional information regarding the leases, including PNM’s actions regarding the renewal and purchase options. See Note 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case.

Each of the lease agreements is with a different trust whose beneficial owner is an institutional investor. PNM is not the legal or tax owner of the leased assets. The beneficial owners of the trusts possess all of the voting control and pecuniary interest in the trusts. PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments and other than as discussed in Note 6, PNM has no other financial obligations or commitments to the trusts or the beneficial owners although PNM is responsible for all decommissioning obligations related to its entire interest in PVNGS both during and after termination of the leases. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its Condensed Consolidated Balance Sheets related to the trusts other than accrued lease payments of $3.8 million at September 30, 2016 and $18.4 million at December 31, 2015, which are included in other current liabilities on the Condensed Consolidated Balance Sheets.

Prior to their exercise or expiration, PNM’s fixed rate renewal options were considered to be variable interests in the trusts and resulted in the trusts being considered VIEs under GAAP. PNM evaluated the PVNGS lease arrangements, including actions taken with respect to the renewal and purchase options, and concluded that it did not have the power to direct the activities that most significantly impacted the economic performance of the trusts and, therefore, was not the primary beneficiary of the trusts under GAAP. Upon execution of documents establishing terms of the asset purchases or lease extensions, PNM’s variable interest in the trusts ceased to exist.

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 a $40.0 million letter of credit support under the PNMR Revolving Credit Facility 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 letter of credit support result in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital could be subject to loss in the event WSJ were to default under the Westmoreland Loan and/or performance under the letter of credit support was required.  Principal payments under the Westmoreland Loan began on August 1, 2016 and are required quarterly thereafter. Interest is also paid quarterly beginning on May 1, 2016.

At September 30, 2016, the amount outstanding under the Westmoreland Loan was $110.0 million, after the August 1, 2016 scheduled principal payment of $15.0 million, and is reflected on the Condensed Consolidated Balance Sheet net of unamortized fees. In addition, interest receivable of $1.5 million is included in Other receivables. In August 2016, the $40.0 million letter of credit support was reduced to $30.3 million. 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 $15.0 million plus interest of $2.3 million is due on November 1, 2016. As of October 21, 2016, $17.3 million was held in a 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. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations.  In such event, NM Capital would likely engage a third-party mining company to operate SJCC so that operations of the mine are not disrupted. Since the acquisition of SJCC by WSJ for approximately $125.0 million is a recently negotiated, arms-length transaction between Westmoreland and BHP, the amount should approximate the fair value of SJCC.  Therefore, if WSJ were to default, NM Capital should be able to acquire assets of approximately the value of the Westmoreland Loan without a significant loss. Furthermore, PNMR considers the possibility of loss under the letter of credit support to be remote since the purpose of posting the bonds is to provide assurance that SJCC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the CSA. Also, much of the mine reclamation activities will not be performed for many years in the future, including after the expiration of the CSA and the final maturity of the Westmoreland Loan. In addition, each of the SJGS participants has established, and funds, a trust to meet its future reclamation obligations.

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

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Lease Commitments

9 Months Ended

Sep. 30, 2016

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 and, through April 1, 2015, leased an interest in the EIP transmission line. 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 2015 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 31.25 MW of the entitlement from PVNGS Unit 2 and $85.2 million to the lessors under the other two leases for 32.76 MW of the entitlement from PVNGS Unit 2. See Note 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case.

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 September 30, 2016, amounts due to the lessors under the circumstances described above would be up to $176.1 million, payable on January 15, 2017 in addition to the scheduled lease payments due on January 15, 2017.

At March 31, 2015, PNM owned 60% of the EIP and leased the other 40%, under a lease that expired on April 1, 2015. PNM purchased the leased capacity at fair market value, which the parties agreed was $7.7 million, on April 1, 2015.

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Fair Value of Derivative and Other Financial Instruments

9 Months Ended

Sep. 30, 2016

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 2015 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 for commodity derivatives 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 fair values, there are inherent limitations in any estimation technique.

Energy Related Derivative Contracts

Overview

The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. PNM’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. However, as discussed below, PNM has hedging arrangements for the output of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases.

Commodity Risk

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

Accounting for Derivatives

Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. During the nine months ended September 30, 2016 and the year ended December 31, 2015, 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
	September 30, 2016			December 31, 2015
PNMR and PNM	(In thousands)
Current assets	$	3,949		$	3,813
Deferred charges	747			2,622
	4,696			6,435
Current liabilities	(2,423		)	(1,859		)
Long-term liabilities	(58		)	—
	(2,481		)	(1,859		)
Net	$	2,215		$	4,576

Included in the above table are $2.7 million of current assets and $0.6 million of deferred charges at September 30, 2016 and $3.0 million of current assets and $2.6 million of deferred charges at December 31, 2015 related to contracts for the sale of energy from PVNGS Unit 3 through 2017 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at September 30, 2016 and December 31, 2015.

At September 30, 2016 and December 31, 2015, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at September 30, 2016 and December 31, 2015, amounts posted as cash collateral under margin arrangements were $3.0 million and $2.7 million for both PNMR and PNM. At September 30, 2016 and December 31, 2015, obligations to return cash collateral were $0.1 million and $0.1 million for both PNMR and PNM. Cash collateral amounts are included in other current assets and other current liabilities on the 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, less than $0.1 million of deferred charges, and less than $0.1 million of current liabilities at September 30, 2016 and $0.4 million of current assets and $0.2 million of current liabilities at December 31, 2015 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the 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						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
PNMR and PNM	(In thousands)
Electric operating revenues	$	1,652		$	6,823		$	214		$	7,354
Cost of energy	(1		)	(78		)	(1,113		)	(227		)
Total gain (loss)	$	1,651		$	6,745		$	(899	)	$	7,127

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
September 30, 2016	200,000	(2,924,985	)
December 31, 2015	577,481	(3,405,843	)

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

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

Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
PNMR and PNM
September 30, 2016	$	—	$	—	$	—
December 31, 2015	$	839	$	—	$	839

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently included in retail rates, that unit’s power is being sold in the wholesale market. PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers beginning on January 1, 2018. As of September 30, 2016, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2017, at market price plus a premium.  Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates for substantially all of the sales through 2017, which average approximately $26 per MWh in 2016 and $29 per MWh in 2017.

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 post-term reclamation costs related to the coal mines serving SJGS and Four Corners (Note 11). At September 30, 2016 and December 31, 2015, the fair value of available-for-sale securities included $258.6 million and $249.1 million for the NDT and $12.4 million and $9.9 million for the mine reclamation trusts. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	September 30, 2016				December 31, 2015
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	4,831	$	—	$	10,700
Equity securities:
Domestic value	8,345		63,666		11,610		44,505
Domestic growth	5,619		47,996		11,163		61,078
International and other	2,868		28,304		1,569		27,961
Fixed income securities:
U.S. Government	696		37,152		178		27,880
Municipals	2,490		52,459		3,672		58,576
Corporate and other	1,698		36,627		628		28,342
	$	21,716	$	271,035	$	28,820	$	259,042

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the change in realized impairment losses of $0.1 million and $1.0 million for the three and nine months ended September 30, 2016 and $(2.4) million and $(3.2) million for the three and nine months ended September 30, 2015.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In thousands)
Proceeds from sales	$	86,975		$	71,576		$	280,989		$	166,097
Gross realized gains	$	7,026		$	8,998		$	27,273		$	22,463
Gross realized (losses)	$	(2,565	)	$	(4,014	)	$	(12,913	)	$	(7,133	)

Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. At September 30, 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 September 30, 2016, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR
	(In thousands)
Within 1 year	$	4,349	$	—
After 1 year through 5 years	36,265		119,987
After 5 years through 10 years	24,512		—
After 10 years through 15 years	10,286		—
After 15 years through 20 years	9,446		—
After 20 years	41,380		—
	$	126,238	$	119,987

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 nine months ended September 30, 2016 and the year ended December 31, 2015.

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

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at September 30, 2016 and December 31, 2015 for items recorded at fair value.

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2016	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	4,831		$	4,831	$	—
Equity securities:
Domestic value	63,666			63,666		—
Domestic growth	47,996			47,996		—
International and other	28,304			28,304		—
Fixed income securities:
U.S. Government	37,152			35,879		1,273
Municipals	52,459			—		52,459
Corporate and other	36,627			6,849		29,778
	$	271,035		$	187,525	$	83,510
Commodity derivative assets	$	4,696		$	—	$	4,696
Commodity derivative liabilities	(2,481		)	—		(2,481		)
Net	$	2,215		$	—	$	2,215
December 31, 2015
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	10,700		$	10,700	$	—
Equity securities:
Domestic value	44,505			44,505		—
Domestic growth	61,078			61,078		—
International and other	27,961			27,961		—
Fixed income securities:
U.S. Government	27,880			26,608		1,272
Municipals	58,576			—		58,576
Corporate and other	28,342			6,500		21,842
	$	259,042		$	177,352	$	81,690
Commodity derivative assets	$	6,435		$	—	$	6,435
Commodity derivative liabilities	(1,859		)	—		(1,859		)
Net	$	4,576		$	—	$	4,576

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
September 30, 2016	(In thousands)
PNMR
Long-term debt	$	2,308,340	$	2,508,344	$	—	$	2,508,344	$	—
Westmoreland Loan	$	109,783	$	119,987	$	—	$	—	$	119,987
Other investments	$	428	$	1,030	$	428	$	—	$	602
PNM
Long-term debt	$	1,631,587	$	1,768,115	$	—	$	1,768,115	$	—
Other investments	$	197	$	197	$	197	$	—	$	—
TNMP
Long-term debt	$	420,802	$	482,385	$	—	$	482,385	$	—
Other investments	$	231	$	231	$	231	$	—	$	—
December 31, 2015
PNMR
Long-term debt	$	2,091,948	$	2,264,869	$	—	$	2,264,869	$	—
Investment in PVNGS lessor notes	$	8,587	$	8,947	$	—	$	—	$	8,947
Other investments	$	604	$	1,269	$	604	$	—	$	665
PNM
Long-term debt	$	1,580,677	$	1,703,209	$	—	$	1,703,209	$	—
Investment in PVNGS lessor notes	$	8,587	$	8,947	$	—	$	—	$	8,947
Other investments	$	366	$	366	$	366	$	—	$	—
TNMP
Long-term debt	$	361,411	$	411,661	$	—	$	411,661	$	—
Other investments	$	238	$	238	$	238	$	—	$	—

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2016

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 2015 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.

The stock-based compensation expense related to restricted stock awards without performance or market conditions for awards to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for other such awards is amortized to compensation expense over the shorter of the requisite vesting period, which is generally three years, 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 September 30, 2016 and December 31, 2015, PNMR had unrecognized expense related to stock awards of $5.9 million and $5.7 million, which are expected to be recognized over an average of 1.9 and 1.4 years. 

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:

	Nine Months Ended September 30,
Restricted Shares and Performance Based Shares	2016			2015
Expected quarterly dividends per share	$	0.22		$	0.20
Risk-free interest rate	0.94		%	0.92		%
Market-Based Shares
Dividend yield	2.74		%	2.87		%
Expected volatility	20.44		%	18.73		%
Risk-free interest rate	0.97		%	1.00		%

The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the nine months endedSeptember 30, 2016:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2015	245,094		$	24.81	569,342		$	19.35
Granted	190,276		$	26.49	—		$	—
Exercised	(213,812	)	$	23.44	(241,468	)	$	27.61
Forfeited	(714	)	$	29.54	(2,000	)	$	12.22
Expired	—		$	—	(8,200	)	$	24.85
Outstanding at September 30, 2016	220,844		$	27.58	317,674		$	12.97

PNMR’s stock-based compensation program provides for performance and market targets through 2018. Included as granted and exercised in the above table are 79,619 previously awarded shares that were earned for the 2013 through 2015 performance measurement period and approved by the Board in February 2016 (based upon achieving market targets at “target” levels, weighted at 60%, and performance targets at “threshold” levels, weighted at 40%). Excluded from the above table are maximums of 165,628, 166,797, and 147,031 shares for the three-year performance periods ending in 2016, 2017, and 2018 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR’s common stock if PNMR meets specific market targets at the end of 2016 and she remains an employee of the Company. Under the agreement, she would receive 35,000 of the total shares if PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2014 and the Board approved her receiving the 35,000 shares in February 2015. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2016, he would receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. If the target for the first performance period is not met, but the target for the second performance period is met, he would receive both awards, less any amount received previously under the agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include any restricted stock shares under this retention award agreement.

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

At September 30, 2016, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.3 million with a weighted-average remaining contract life of 2.22 years. At September 30, 2016, no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date.

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

	Nine Months Ended September 30,
Restricted Stock	2016		2015
Weighted-average grant date fair value	$	26.49	$	20.34
Total fair value of restricted shares that vested (in thousands)	$	5,011	$	6,503
Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	—
Total intrinsic value of options exercised (in thousands)	$	1,208	$	1,814

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Financing

9 Months Ended

Sep. 30, 2016

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. Each of the revolving credit facilities and the Company’s term loans contains one financial covenant, which requires the maintenance of debt-to-capital ratios of less than or equal to 65% and generally include customary covenants, events of default, cross default provisions, and change of control provisions. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. Additional information concerning financing activities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2015 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, which was 1.42% at September 30, 2016, 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 loss of $0.7 million at September 30, 2016, which is included in Other deferred credits on the Condensed Consolidated Balance Sheets, and a fair value gain of $0.1 million at December 31, 2015, using Level 2 inputs under GAAP determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.

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, 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 3.51% at September 30, 2016. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding of $125.0 million (the “Westmoreland Loan”) to a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price of the stock of SJCC. The BTMU Term Loan Agreement provides that the amount outstanding thereunder must be reduced by at least $5.0 million quarterly beginning on November 1, 2016. NM Capital is also required to utilize the net proceeds of all amounts received under the Westmoreland Loan, after income taxes and fees, to make principal and interest payments on the BTMU Term Loan Agreement. The principal balance outstanding under the BTMU Term Loan Agreement was $107.8 million at September 30, 2016. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $45.1 million on the BTMU Term Loan Agreement in the twelve months ended September 30, 2017.

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

On May 20, 2016, PNM entered into a $175.0 million term loan agreement (the “PNM 2016 Term Loan Agreement”) between PNM and JPMorgan Chase Bank, N.A., as lender and administrative agent. The PNM 2016 Term Loan Agreement bears interest at a variable rate, which was 1.15% at September 30, 2016, and has a maturity date of November 17, 2017. PNM used a portion of the proceeds of the PNM 2016 Term Loan Agreement to prepay without penalty the $125.0 million outstanding under the PNM Multi-draw Term Loan, which had a scheduled maturity of June 21, 2016.

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

On October 21, 2016, PNMR entered into a letter of credit arrangement with JPMorgan Chase Bank, N.A. under which letters of credit aggregating $30.3 million (the “JPM LOCs”) were issued to replace letters of credit issued from available capacity under the PNMR Revolving Credit Facility. The letters of credit issued from available capacity under the PNMR Revolving Credit Facility will be surrendered and canceled upon acceptance of the JPM LOCs by the surety companies that issue the reclamation bonds. The letters of credit facilitate the posting of reclamation bonds, which SJCC was required to post in connection with permits relating to the operation of the San Juan mine (Note 11).

Short-term Debt

The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million, both of which mature on October 31, 2020. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. The TNMP Revolving Credit Facility matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At September 30, 2016, the weighted average interest rate was 1.78% for the PNMR Revolving Credit Facility, 1.66% for the PNM Revolving Credit Facility, 1.68% for the PNM New Mexico Credit Facility, and 1.38% for borrowings outstanding under the twelve-month $150.0 million PNMR Term Loan Agreement, which matures in December 2016. Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2016		2015
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	22,400	$	—
PNM New Mexico Credit Facility	20,000		—
TNMP Revolving Credit Facility	—		59,000
PNMR:
PNMR Revolving Credit Facility	163,500		41,600
PNMR Term Loan Agreement	150,000		150,000
	$	355,900	$	250,600

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $36.5 million, $2.5 million, and $0.1 million at September 30, 2016 that reduce the available capacity under their respective revolving credit facilities.

At October 21, 2016, PNMR, PNM, and TNMP had $100.4 million, $373.5 million, and $74.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $44.0 million of availability under the PNM New Mexico Credit Facility. Total availability at October 21, 2016, on a consolidated basis, was $592.8 million for PNMR. As of October 21, 2016, PNM and TNMP had no borrowings from PNMR under intercompany loan agreements. At October 21, 2016, PNMR, PNM, and TNMP had consolidated invested cash of $1.8 million, none, and $0.3 million.

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Pension and Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2016

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 2015 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.

PNM Plans

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

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	35		$	51		$	—	$	—
Interest cost	7,577			7,064			1,087			1,022			203		190
Expected return on plan assets	(8,854		)	(9,831		)	(1,371		)	(1,403		)	—		—
Amortization of net (gain) loss	3,455			3,705			286			491			64		81
Amortization of prior service cost	(241		)	(241		)	(7		)	(160		)	—		—
Net periodic benefit cost	$	1,937		$	697		$	30		$	1		$	267	$	271
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	105		$	153		$	—	$	—
Interest cost	22,731			21,191			3,260			3,067			609		570
Expected return on plan assets	(26,562		)	(29,492		)	(4,113		)	(4,208		)	—		—
Amortization of net (gain) loss	10,365			11,115			858			1,474			192		243
Amortization of prior service cost	(724		)	(724		)	(22		)	(481		)	—		—
Net periodic benefit cost	$	5,810		$	2,090		$	88		$	5		$	801	$	813

PNM made contributions to its pension plan trust of zero and $30.0 million in the three and nine months ended September 30, 2015 and does not anticipate making any contributions to the pension plan in 2016-2020, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.8% to 5.7%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made contributions to the OPEB trust of $0.8 million and $2.4 million in the three and nine months ended September 30, 2016 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2015. PNM does not expect to make additional contributions to the OPEB trust in 2016 and does not expect to make contributions for 2017-2020.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.2 million in the three and nine months ended September 30, 2016 and $0.4 million and $1.2 million in the three and nine months ended September 30, 2015 and are expected to total $1.5 million during 2016 and $5.9 million for 2017-2020.

TNMP Plans

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

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	—		$	—		$	46		$	62		$	—	$	—
Interest cost	826			761			169			152			10		9
Expected return on plan assets	(986		)	(1,105		)	(122		)	(130		)	—		—
Amortization of net (gain) loss	175			195			(10		)	—			1		1
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost (Income)	$	15		$	(149	)	$	83		$	84		$	11	$	10
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	—		$	—		$	139		$	185		$	—	$	—
Interest cost	2,478			2,282			508			456			30		27
Expected return on plan assets	(2,957		)	(3,315		)	(367		)	(390		)	—		—
Amortization of net (gain) loss	525			586			(30		)	—			1		3
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost (Income)	$	46		$	(447	)	$	250		$	251		$	31	$	30

TNMP made no contribution to its pension trust in 2015 and does not anticipate making any contributions in 2016-2020, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.8% to 5.7%. 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 no contributions to the OPEB trust in the three and nine months ended September 30, 2016 and 2015. TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2016 and $1.4 million for 2017-2020. 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 and nine months ended September 30, 2016 and 2015 and are expected to total $0.1 million during 2016 and $0.4 million in 2017-2020.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

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 2015 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. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. In the first quarter of 2015, PNM recorded $4.3 million, including $3.1 million credited back to PNM’s customers, for its share of the settlement under this process for costs incurred from July 2011 through June 2014. PNM now records estimated claims quarterly. The settlement agreement terminates upon payment of costs incurred through December 31, 2016, unless extended by mutual written agreement.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At September 30, 2016 and December 31, 2015, PNM had a liability for interim storage costs of $12.0 million and $12.2 million included in other deferred credits.

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

On June 8, 2012, the DC Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners 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. PNM is unable to predict the outcome of this matter.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. 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 2015 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 $76.8 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 will increase with the installation of SNCR and BDT equipment.

On December 16, 2015, following oral argument, the NMPRC issued a final order regarding SJGS. As provided in that order:

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

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

• PNM is granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017, including transmission assets associated with PVNGS Unit 3, (estimated to aggregate approximately $152 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 anticipates developing two resource portfolios in its 2017 IRP to be filed in July 2017, one with SJGS continuing beyond mid-2022 and one where it is shutdown)

• 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

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

At December 31, 2015, PNM estimated the undepreciated net book value of SJGS Units 2 and 3 at December 31, 2017 would be approximately $255.3 million, 50% of which would be recovered over a 20 year period, including a return on the unrecovered amount at PNM’s WACC. At December 31, 2015, PNM recorded a $127.6 million regulatory disallowance to reflect the write-off of the 50% of the estimated December 31, 2017 net book value that will not be recovered. The ultimate amount of the disallowance will be dependent on the actual December 31, 2017 net 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. At December 31, 2015, PNM recorded losses for regulatory disallowances and restructuring costs, aggregating $165.7 million, reflecting the above disallowance, 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”). Additional information about the CSA is discussed under Coal Supply below and in Note 16 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K.

In the three months ended March 31, 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 an expense of $0.8 million that 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 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. In the three months ended September 30, 2016, PNM recorded $5.2 million of additional regulatory disallowances and restructuring costs, including $4.8 million related to a refinement of the estimated liability for coal mine reclamation resulting from the new coal mine reclamation arrangement and $0.4 million from a further revision of estimated December 31, 2017 projected book value of SJGS Units 2 and 3 and the other unrecoverable costs. At September 30, 2016, the carrying value for PNM’s current ownership share of SJGS Units 2 and 3 is comprised of plant in service of $471.6 million and accumulated depreciation and amortization of $201.4 million for a net undepreciated book value of $270.2 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 $141.6 million at September 30, 2016.

On January 14, 2016, NEE filed, with the NM Supreme Court, a Notice of Appeal of the NMPRC’s December 16, 2015 order. On July 22, 2016, NEE filed a brief alleging that the NMPRC’s decision violated NM 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.  PNM’s response brief is due November 2, 2016. In addition, on February 5, 2016, NEE filed, with the NMPRC, a motion for reconsideration of that final order based on developments related to the loan made by NM Capital to facilitate the sale of SJCC, which is described under Coal Supply below. NEE alleged the loan is a transaction that, under the New Mexico Public Utility Act, requires prior NMPRC approval. PNM filed its response to NEE’s motion for reconsideration on February 18, 2016. The NEE motion was denied by operation of law because the NMPRC did not act on the motion. On March 31, 2016, NEE filed, with the NMPRC, a complaint 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 to 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 2015 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.

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

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 1-3, which were shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.

PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $90.1 million, including amounts incurred through September 30, 2016 and PNM’s AFUDC. PNM will seek recovery from its ratepayers of all costs that are ultimately incurred. 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 December 21, 2015, several environmental groups filed a notice of intent to sue the OSM and other federal agencies under the ESA, alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review was not in accordance with applicable law. The environmental review was undertaken as part of the DOI’s review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners.  This review process also required separate environmental impact evaluations under NEPA and culminated in the issuance of a Record of Decision justifying the agency action extending the life of the plant and the adjacent mine.

On April 20, 2016, the same environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for the District of Arizona.  Expanding upon the December 2015 ESA notice, the lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016.  The court granted APS’ motion to intervene in the litigation on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, the Navajo Transitional Energy Company, LLC (“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. 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. Those deadlines will 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 asking the court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court granted the applications to stay the Clean Power Plan pending judicial review of the rule.  The US Supreme Court issued a one-page order that stated, “The EPA rule to have states cut power sector carbon dioxide (CO₂) emissions 32% by 2030 is stayed pending disposition of the applicants’ petitions for review in the United States Court of Appeals for the District of Columbia Circuit.” The vote was 5-4 among the US Supreme Court Justices. The decision means the Clean Power Plan is not in effect and states are not obliged to comply with its requirements. If the rule prevails through the legal challenges, states will be able to resume preparing state plans where they left off and may still have six more months to prepare initial plans and 2.5 years for final plans. The DC Circuit heard oral arguments on September 27, 2016 in the case challenging the Clean Power Plan.  A decision by the DC Circuit is not expected until sometime in 2017. The stay will remain in effect pending US Supreme Court review if such review is sought.

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

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. The due date for comments to EPA on the program has been extended to November 1, 2016.

PNM’s review of the new CO₂ emission reductions standards is ongoing and the assessment of its impacts will depend on the outcome of the judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance.

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO₂,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and 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. The next compliance date is in January 2017, when NMED will submit their formal modeling report and recommendations regarding attainment status to EPA. Thereafter, every July, NMED must submit a report to EPA documenting annual SO₂ emissions from SJGS and the associated compliance status.

EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications required under its amended NSR air permit for the installation of SNCRs and installation of BDT equipment to reduce fugitive emissions, including NOx, SO₂ and particulate matter, will assist the plant in complying with the particulate matter NAAQS.

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

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 will use to determine their initial designation recommendations by October 1, 2016. EPA recommends that states and tribes use the three most recent years of quality assured monitoring data available (e.g., 2013 to 2015) to recommend designations. States and tribes may also have preliminary 2016 data that may be used. EPA will 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 their 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.

Four Corners Coal Mine

In 2012, several environmental groups filed a lawsuit in federal district court against the OSM challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners (“Area IV North”). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM took action to cure the defect in its permitting process identified by the court. The owner of the mine appealed to the Tenth Circuit. On December 29, 2015, OSM took action to cure the defect in its permitting process by issuing a revised environmental assessment with a finding of no new significant impact and reissued the permit. On March 30, 2016, the Tenth Circuit vacated and dismissed the appeal on mootness grounds due to OSM’s revised environmental assessment and reapproval of the permit at issue.

WEG v. OSM NEPA Lawsuit

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

Navajo Nation Environmental Issues

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

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 has been 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 National Pollutant Discharge Elimination System (“NPDES”) permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS has indicated that it does not expect such costs to be material.

Effluent Limitation Guidelines

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

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

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

Based upon the requirements of the final Steam Electric Effluent Guidelines Rule, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. Until a draft NPDES permit is proposed for Four Corners, APS is uncertain what will be required to comply with the finalized effluent limitations.  PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. 

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the 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 gasoline remediation of the site under the supervision of NMED and qualified costs of the work will be eligible for payment through the New Mexico Corrective Action Fund (“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 remediation tasks were approved by the Petroleum Storage Tank Bureau. PNM submitted a monitoring plan consisting of a compilation of the data associated with the recent monitoring activities conducted under the CAF to NMED on October 3, 2016. Following review of the data by NMED, PNM, and NMED will develop plans for the next phase of work under the CAF.

Coal Combustion Byproducts Waste Disposal

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

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

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

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

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.

The rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCB rules. The CCB rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in 2016 and will likely be influenced by EPA’s rule. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows. PNM would seek recovery from its ratepayers of all CCB costs that are ultimately incurred.

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are supplied by SJCC. Through January 31, 2016, SJCC was a wholly owned subsidiary of BHP and supplied processed coal for operation of SJGS under an underground coal sales agreement (“UG-CSA”) that was to expire on December 31, 2017. The parties to the UG-CSA were SJCC, PNM, and Tucson. SJCC holds certain federal, state, and private coal leases. Under the UG-CSA, SJCC was reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and received a return on its investment. In addition to coal delivered to meet the current needs of SJGS, PNM prepaid SJCC for certain coal mined but not yet delivered to the plant site. At September 30, 2016 and December 31, 2015, prepayments for coal, which are included in other current assets, amounted to $54.1 million (including amounts purchased from the existing SJGS participants discussed below) and $49.0 million.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS after the expiration of the UG-CSA. 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”), among NM Capital, The Bank of Tokyo-Mitsubishi UFJ, Ltd. (“BTMU”), as lender, and BTMU, as 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, entered into a Guaranty Agreement, dated as of February 1, 2016, with BTMU (the “Guaranty”). The BTMU Term Loan Agreement and the Guaranty include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio of 65%, and customary events of default consistent with PNMR’s other term loan agreements. In addition, the BTMU Term Loan Agreement has a cross default provision and a change of control provision. The balance outstanding under the BTMU Term Loan Agreement was $107.8 million at September 30, 2016.

The Westmoreland Loan is a $125.0 million loan agreement among NM Capital, as lender, WSJ, as borrower, SJCC and its affiliate, as guarantors, BTMU, as Administrative Agent, and MUFG Union Bank, N.A., as Depository Bank. The Westmoreland Loan became effective as of February 1, 2016, and has a maturity date of February 1, 2021. The Westmoreland Loan initially bears interest at a rate of 7.25% plus LIBOR and escalates over time. The Westmoreland Loan has been structured to encourage prepayments and early retirement of the debt. WSJ must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. In addition, the Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. At September 30, 2016, the amount outstanding under the Westmoreland Loan was $110.0 million, after the August 1, 2016 scheduled principal payment of $15.0 million. The next principal payment of $15.0 million plus interest of $2.3 million is due on November 1, 2016. As of October 21, 2016, $17.3 million was held in a 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 was required to post reclamation bonds of $161.6 million with the NMMMD. In April 2016, NMMMD reduced SJCC’s bonding requirements to $118.7 million. In order to facilitate the posting of reclamation bonds by a surety on behalf of SJCC, a Reclamation Bond Agreement (the “Reclamation Bond Agreement”) was entered into by PNMR, Westmoreland, and SJCC with the surety. In connection with the Reclamation Bond Agreement, PNMR used $40.0 million of the available capacity under the PNMR Revolving Credit Facility to support a bank letter of credit arrangement for the benefit of the surety. On July 19, 2016, these reclamation bonds were released by NMMMD upon acceptance of $118.7 million of replacement reclamation bonds from alternate surety companies, which are supported by letters of credit aggregating $30.3 million issued from available capacity under the PNMR Revolving Credit Facility. The Reclamation Bond Agreement was terminated effective August 3, 2016 and the prior letter of credit was surrendered and canceled. On October 21, 2016, PNMR entered into separate letter of credit arrangements with a bank to replace the letters of credit issued from available capacity under the PNMR Revolving Credit Facility. The letters of credit issued from available capacity under the PNMR Revolving Credit Facility will be surrendered and canceled upon acceptance of the replacement letters of credit by the surety companies that issued the reclamation bonds.

Four Corners

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, beginning in July 2016 and expiring in 2031, was entered into with that entity. The BHP subsidiary is to be retained as the mine manager and operator until December 2016. Coal costs are anticipated to increase approximately 40% in the first year of the new contract. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

Coal Mine Reclamation

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

In 2015, PNM updated its final reclamation costs estimates to reflect the terms of the new reclamation services agreement with Westmoreland, discussed above, and changes resulting from the approval of the 2015 SJCC Mine Permit Plan. 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 expectation, and common mine reclamation practices incorporated into the 2015 SJCC Mine Permit reflect an increase in the 2015 reclamation cost estimate. The impacts of these increases, amounting to $16.5 million, were recorded at December 31, 2015 and were reflected in regulatory disallowances and restructuring costs.

Upon effectiveness of the CSA and the RA, PNM, on behalf of the SJGS owners, coordinated a more detailed coal mine reclamation cost study, which was completed in the third quarter of 2016. To complete the study, PNM was provided access to the mine site and obtained supporting data from Westmoreland, allowing for the 2015 study to be refined with a more extensive engineering analysis. The new reclamation cost estimate reflects the terms of the new reclamation services agreement with Westmoreland and continuation of mining operations through 2053. The study indicates an increase in the reclamation cost estimate. PNM’s share of the increase is $4.8 million, which was recorded at September 30, 2016 and is reflected in regulatory disallowances and restructuring costs in the Condensed Consolidated Statements of Earnings. The current estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new agreement for coal supply.

Based on the 2016 estimates and PNM’s current ownership share of SJGS, PNM’s remaining payments as of September 30, 2016 for mine reclamation, in future dollars, are estimated to be $103.0 million for the surface mines at both SJGS and Four Corners and $129.4 million for the underground mine at SJGS. At September 30, 2016 and December 31, 2015, liabilities, in current dollars, of $41.4 million and $38.8 million for surface mine reclamation and $13.9 million and $11.4 million for underground mine reclamation were recorded in other deferred credits.

Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation liabilities associated with the supply of coal from the San Juan mine. On June 1, 2012, the SJGS owners entered into a trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the UG-CSA. As part of the restructuring of SJGS ownership (see SJGS Ownership Restructuring Matters above), the SJGS owners and PNMR Development negotiated the terms of an amended agreement to fund post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable Reclamation Trust, and periodically deposit funding into the Reclamation Trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels. Based on the existing trust fund balance at September 30, 2016, PNM’s required contributions to its Reclamation Trust fund would be $3.5 million, $4.7 million, and $5.1 million in 2016, 2017, and 2018.

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

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

Continuous Highwall Mining Royalty Rate

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

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

Four Corners Severance Tax Assessment

On May 23, 2013, the New Mexico Taxation and Revenue Department (“NMTRD”) issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners. For procedural reasons, on behalf of the Four Corners co-owners, including PNM, the coal supplier made a partial payment of the assessment and immediately filed a refund claim with respect to that partial payment in August 2013. NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. On June 30, 2015, the court ruled that the assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. NMTRD filed a notice of appeal with the New Mexico Court of Appeals on August 31, 2015. In March 2016, the parties settled this matter. PNM has paid its share of the settlement, which was $0.1 million in addition to amounts previously paid.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with this act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.5 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $375 million, which is provided by American Nuclear Insurers. The remaining balance of $13.1 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential retrospective premium assessment per incident for all three units is $38.9 million, with a maximum annual payment limitation of $5.8 million, to be adjusted periodically for inflation.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). A sublimit of $2.25 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium assessments of $5.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to certain policy conditions, sublimits, and exclusions.

Water Supply

Because of New Mexico’s arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast long-term weather patterns. Public policy, local, state and federal regulations, and litigation regarding water could also impact PNM operations. To help mitigate these risks, PNM has secured permanent groundwater rights for the existing plants at Reeves Station, Rio Bravo, Afton, Luna, Lordsburg, and La Luz. Water availability is not an issue for these plants at this time. However, prolonged drought, ESA activities, and a federal lawsuit by the State of Texas (suing the State of New Mexico over water deliveries) could pose a threat of reduced water availability for these plants.

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

PVNGS Water Supply Litigation

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

San Juan River Adjudication

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

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

Rights-of-Way Matter

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

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 2 of the 5 allotments at issue based on the Navajo Nation’s fractional interest in the land. PNM’s motion for reconsideration of this ruling was denied. On March 31, 2016, the Tenth Circuit granted PNM’s petition to appeal the December 1, 2015 ruling. On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. Both matters have been consolidated and are stayed while PNM pursues its appeal before the Tenth Circuit. On June 27, 2016, PNM filed its opening brief in the Tenth Circuit. Amicus briefs were filed in support of PNM’s position. On October 5, 2016, the United States, the Navajo Nation, and individual allottees filed their response briefs. After the response briefs were filed, other entities requested leave to file amicus briefs addressing arguments raised in the United States’ response brief. PNM cannot predict the outcome of these matters.

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Regulatory and Rate Matters

9 Months Ended

Sep. 30, 2016

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 2015 Annual Reports on Form 10-K.

PNM

New Mexico 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. The 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 due to issues identified in PNM’s 2016 renewable energy procurement plan and extended the rate suspension period to July 31, 2016. As ordered by the NMPRC, PNM filed supplemental testimony in the NM 2015 Rate Case demonstrating that PNM’s FPPAC is designed to properly recover its fuel and purchased power expenses. See Renewable Portfolio Standard below. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016, pursuant to the terms of the initial sales-leaseback transactions (Note 6). A subsequent public hearing was held in June 2016. After the close of the April hearing, the NMPRC further extended the rate suspension period through August 31, 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.  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, include:

• The RD proposed a ROE of 9.575% compared to the 10.5% requested by PNM

• The RD proposed 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 are currently $0.8 million per year), 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

• The RD proposed that PNM not recover from retail customers any of the rent expense, which aggregate $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 not recover related property taxes, which are currently $1.5 million per year; 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

• The RD proposed that PNM not recover 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 current rate request

• The RD proposed that $4.5 million of amounts recorded as regulatory assets and deferred charges not be recovered from retail customers

The RD recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. The RD also proposed that all fuel costs be removed from base rates and be recovered through the FPPAC. The RD would credit retail customers with 100% of the New Mexico jurisdictional portion of revenues from refined coal (a third-party pre-treatment process) at SJGS. In addition, the RD would remove recovery of the costs of power obtained from New Mexico Wind from the FPPAC and include recovery of those costs through PNM’s renewable energy rider discussed below. The RD recommended continuation of the renewable energy rider and certain aspects of PNM’s proposals regarding rate design, but would not approve certain other rate design proposals or PNM’s request for a revenue decoupling pilot program. The RD proposed approving PNM’s proposals for revised depreciation rates (with one exception), the inclusion of CWIP in rate base, and ratemaking treatment of the prepaid pension asset. The RD did not preclude PNM from supporting the prudence of the PVNGS purchases and lease renewals in its next general rate case and seeking recovery of those costs. PNM disagreed with many of the key conclusions reached by the hearing examiner in the RD and filed exceptions to defend its prudent utility investments. Other parties also filed exceptions to the RD. The NMPRC extended the rate suspension period to end on September 30, 2016.  

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

• 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 final order was issued

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

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

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

On September 30, 2016, PNM filed a Notice of Appeal with the NM Supreme Court regarding the final order in the NM 2015 Rate Case. Subsequently, NEE, NMIEC, and ABCWUA filed notices of cross-appeal. On October 26, 2016, PNM filed, with the NM Supreme Court, a statement of issues related to its appeal, 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 final 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 previously leased capacity

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

The court has taken no action with respect to the appeals. 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.

As of September 30, 2016, PNM evaluated the accounting consequences of the final 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 final order will remain in effect. Accordingly, at September 30, 2016, PNM recorded a pre-tax regulatory disallowance of $6.8 million representing 15 months of capital cost recovery of its investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT that the final order disallowed. In addition, PNM recorded a pre-tax regulatory disallowance for $4.5 million of costs recorded as regulatory assets and deferred charges, which the final order disallowed and which PNM did not propose to challenge in its appeal, since PNM can no longer assert that those assets are probable of being recovered through the ratemaking process. The NMPRC’s final order approved PNM’s request to record a regulatory asset to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from an extension of the income tax provision for fifty percent bonus depreciation. The impact, net of federal income taxes, amounts to $2.1 million, which is reflected as a reduction of income tax expense on the Condensed Consolidated Statement of Earnings.

PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurred and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is reasonably possible that its appeals will be successful, it cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record further pre-tax losses related to any unsuccessful issues. The amounts of any such losses 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 September 30, 2016, the 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 final order; the net book value of such excess amount was $76.9 million, after considering the loss recorded at September 30, 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 $41.7 million, after considering the loss recorded at September 30, 2016

• The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $49.9 million, after considering the loss recorded at September 30, 2016

PNM is unable to predict the outcome of this matter.

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.

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 does 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 RPS procurement costs and customers exempt from RPS procurement costs, the NMPRC again approved the plan in an order issued on February 3, 2016. The NMPRC deferred issues related to capped and exempt customers to PNM’s NM 2015 Rate Case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The NM 2015 Rate Case and show cause proceedings were to examine whether PNM miscalculated the FPPAC factor and base fuel costs in its treatment of renewable energy costs and application of the renewable procurement cost caps and exemptions. On April 28, 2016, PNM filed a motion to stay this proceeding until the issuance of a final order in the NM 2015 Rate Case, based on the fact that the issues addressed in the show cause proceeding were being addressed in the NM 2015 Rate Case. On May 4, 2016, the NMPRC granted PNM’s motion. In the September 28, 2016 final order in the NM 2015 Rate Case, the NMPRC ordered the cost of New Mexico Wind to be recovered through PNM’s renewable rider, rather than the FPPAC, and certain other modifications regarding the accounting for renewable energy in PNM’s FPPAC. These modifications do not affect the amount of fuel and purchased power or renewable costs that PNM will collect. PNM cannot predict the outcome of the show cause proceeding.

PNM filed its 2017 renewable energy procurement plan on June 1, 2016. The plan meets RPS and diversity requirements for 2017 and 2018 using existing resources and does not propose any significant new procurements. PNM projects that its plan will slightly exceed the RCT in 2017 and will be within the RCT in 2018. PNM has requested a variance from the RCT in 2017 to the extent the NMPRC determines a variance is necessary. A public hearing was held on September 26, 2016. On October 21, 2016, the Hearing Examiner issued a Recommended Decision recommending that the plan be approved as filed and also found that a variance from the RCT is not required. Pursuant to the REA, the NMPRC must enter an order approving or modifying the plan by November 28, 2016. PNM cannot predict the outcome of this matter.

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In PNM’s NM 2015 Rate Case, the NMPRC authorized continuation of the renewable rider.

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

As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM would be required to refund the excess to customers during May through December of the following year. The NMPRC-approved rate was 10.0% when the renewable rider was initially approved. On April 1, 2016, PNM made a compliance filing at the NMPRC showing that its jurisdictional equity return did not exceed 10.5% in 2015.

Energy Efficiency and Load Management

Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s costs to implement approved programs are recovered through a rate rider.

2016 Energy Efficiency Program Application

On April 15, 2016, PNM filed an application for energy efficiency and load management programs to be offered in 2017. The proposed program portfolio consists of ten programs with a total budget of $28.0 million. The application also seeks approval of an incentive of $2.4 million based on target savings of 75 GWh. The actual incentive will be based upon actual savings achieved. An unopposed stipulation settling all issues was filed on September 29, 2016. The stipulation establishes a method to ensure that funding of PNM’s energy efficiency program is equal to 3% of its retail revenues, with an estimated 2017 energy efficiency funding level of $26.0 million, and a sliding scale profit incentive with a base level of 7.1% of program costs if PNM achieves a minimum proscribed level of energy savings and increasing to a maximum of 9.0% depending on actual energy savings achieved above the minimum. A public hearing was held on October 26 and 27, 2016. PNM cannot predict the outcome of this matter.

Energy Efficiency Rulemaking

On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

Integrated Resource Plan

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they asserted that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also asked that further proceedings on the IRP be held in abeyance until the conclusion of the then pending SJGS abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that docketed a case to determine whether the IRP complies with applicable NMPRC rules. The order also held the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3. The final 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 will be closed with prejudice within thirty days unless good cause is shown why the docket should remain open. On May 31, 2016, NEE filed a request to hold the protests filed against PNM’s IRP in abeyance or to dismiss those protests without prejudice. PNM responded on June 13, 2016 and requested that the NMPRC dismiss the case with prejudice. The NMPRC has not yet acted on its Notice of Proposed Dismissal or the request filed on May 31, 2016.

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 final 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 June 30, 2015, PNM filed an application for a CCN for a 187 MW gas plant to be located at SJGS. This resource was identified as a replacement resource in PNM’s application to retire SJGS Units 2 and 3. On February 12, 2016, PNM filed a motion to withdraw its application and stated that it would file either a new CCN application for a gas-fueled resource or a report on the status of that application. On May 18, 2016, the NMPRC issued an order granting PNM’s request to withdraw the application and closing the case.

On April 26, 2016, PNM filed an application for an 80 MW gas plant to be located at SJGS. The plant would consist of two40 MW aeroderivative units. PNM had requested a final order from the NMPRC by December 1, 2016 to facilitate a 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. The motion was granted on October 20, 2016. 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. PNM will continue to evaluate its resource needs as part of its ongoing resource planning activities and during the 2017 IRP process in which PNM’s entire 20-year portfolio of supply and demand-side resources will be evaluated in terms of cost and reliability requirements. 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 severance for any affected employees. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. On August 5, 2016, PNM filed a motion to suspend its AMI application so that it could evaluate the effect of the final order in the NM 2015 Rate Case. This motion was approved and PNM must either propose a new procedural schedule or file a motion to withdraw the AMI application by November 28, 2016. 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.

Formula Transmission Rate Case

On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would have resulted in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula.

On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003; and (4) setting the proceeding for hearing and settlement judge procedures. On April 1, 2013, PNM made the required compliance filing. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On August 2, 2013, new rates went into effect, subject to refund. In June 2013, May 2014, and March 2015, PNM made additional filings incorporating final 2012, 2013, and 2014 data into the formula rate request. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annualized increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates beginning on April 1, 2015, subject to refund. In May 2015, the settlement judge recommended that FERC approve the settlement. On March 17, 2016, FERC approved the settlement. PNM made the refunds required under the settlement in May 2016.

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

As discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2015 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 will serve all of NEC’s load in 2016 at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC is also paying certain third-party transmission costs that it did not pay in 2014 and partially paid in 2015. The PSA and related transmission agreements will terminate on December 31, 2016. In 2017, PNM will serve 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. Revenues from NEC under the PSA were $4.8 million and $6.3 million in the three months ended September 30, 2016 and 2015 and $14.8 million and $19.7 million in the nine months ended September 30, 2016 and 2015.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011. TNMP has completed its mass deployment by installing 242,246 advanced meters over a 5-year period.

The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service is to be borne by opt-out customers through an initial fee and ongoing monthly charge. As approved by the PUCT, TNMP is recovering $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million through a $36.78 monthly fee. These amounts presume up to 1,081 consumers will elect the non-standard meter service, but TNMP has the right to adjust the fees if the number of anticipated consumers differs from that estimate. As of October 21, 2016, 100 customers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

On October 2, 2015, TNMP filed a reconciliation of the costs and savings of its AMS deployment program with the PUCT. Those costs include $71.0 million in capital costs and $18.0 million in operation and maintenance expenses. However, since the deployment was not complete and the total program costs to date were $1.5 million below the original approved forecasts, TNMP did not request a change to its monthly surcharge amount. On January 8, 2016, the PUCT staff recommended that the PUCT approve TNMP’s reconciliation without adjustment and the PUCT accepted that recommendation on March 25, 2016.

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 8, 2014	$	25.2	$	4.2
March 16, 2015	27.1		4.4
September 10, 2015	7.0		1.4
March 23, 2016	25.8		4.3
September 8, 2016	9.5		1.8

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor (“EECRF”), which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed mandated savings goals). On May 27, 2016, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2017. The total amount requested is $6.1 million, which includes a performance bonus of $0.8 million based on TNMP’s energy efficiency achievements in the 2015 plan year. On July 27, 2016, TNMP reached a settlement with the PUCT staff and intervenors approving a total request of $6.0 million, which includes a performance bonus of $0.8 million. The settlement was approved by the PUCT on September 8, 2016 and updated rates will become effective on March 1, 2017.

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Income Taxes

9 Months Ended

Sep. 30, 2016

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, 2016 and 2015, PNM’s regulatory liability was reduced by $7.1 million and $2.0 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: reduced 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; and increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment.

In 2008, fifty percent bonus tax depreciation was enacted as a temporary two-year stimulus measure as part of the Economic Stimulus Act of 2008. Bonus tax depreciation in various forms has been continuously extended since that time, most recently by the Protecting Americans from Tax Hikes Act of 2015. The 2015 act extends and phases-out bonus tax depreciation through 2019. As a result of the net operating loss carryforwards for income tax purposes created by bonus depreciation, and reduced future income taxes payable resulting from New Mexico House Bill 641, certain tax carryforwards are not expected to be utilized before their expiration. In accordance with GAAP, PNMR and PNM have impaired the tax carryforwards which were not expected to be utilized prior to their expiration. During the three months ended March 31, 2015, the impairment of the New Mexico net operating loss carryforward recorded in 2014 was refined, resulting in an additional impairment of $1.0 million, after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. TNMP had no such impairment in 2015. The Company has not recorded any impairments in 2016. The NMPRC’s final order in PNM’s NM 2015 Rate Case (Note 12) 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 the extension of bonus depreciation. The impact, net of federal income taxes, amounts to $2.1 million, which is reflected as a reduction of income tax expense on the Condensed Consolidated Statement of Earnings.

The Company undertook an analysis of interest income and interest expense applicable to federal income tax matters. The analysis encompassed the impacts of IRS examinations, amended income tax returns, and filings for carrybacks of tax matters to previous taxable years applicable to all years not closed under the IRS rules. As a result of this effort, PNMR received net refunds from the IRS of $6.5 million in the three months ended June 30, 2016. Of the refunds, $2.1 million was recorded as a reduction of interest receivable and $5.1 million was recorded as interest income, which was partially offset by $0.7 million of interest expense. In addition, PNMR incurred $0.9 million in professional fees related to the analysis. Of the net pre-tax impacts aggregating $3.5 million, $2.6 million is reflected in the PNM segment, $0.3 million in the TNMP segment, and $0.6 million in the Corporate and Other segment.

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Related Party Transactions

9 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In thousands)
Services billings:
PNMR to PNM	$	22,189	$	21,894	$	67,192	$	65,961
PNMR to TNMP	6,593		6,707		20,881		20,366
PNM to TNMP	105		136		347		424
TNMP to PNMR	10		—		30		—
Interest billings:
PNMR to TNMP	13		34		112		167
PNMR to PNM	3		10		8		38
PNM to PNMR	38		24		110		79
Income tax sharing payments:
PNMR to PNM	—		—		—		1,450
PNMR to TNMP	—		—		—		—

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Goodwill

9 Months Ended

Sep. 30, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM.

GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. PNMR’s reporting units that have goodwill are PNM and TNMP. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit.

GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity would consider macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity would consider the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity should place more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also should consider positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity would evaluate, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis is not required.

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations.

An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units but a quantitative analysis for others. For its annual evaluations performed as of April 1, 2016, PNMR performed quantitative analyses for both the PNM and TNMP reporting units. PNMR utilized a quantitative analysis for the PNM reporting unit and a qualitative analysis for the TNMP reporting unit as of April 1, 2015. For the quantitative analyses, a discounted cash flow methodology was primarily used to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment.

The annual evaluations performed as of April 1, 2016 and 2015 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2016 and 2015 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 25% and 25%. The April 1, 2016 quantitative evaluation indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 32%. Since the April 1, 2016 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill is contained in Note 19 of Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K.

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Significant Accounting Policies and Responsibility for Financial Statements (Policies)

9 Months Ended

Sep. 30, 2016

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.

Dividends on Common Stock

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year.

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. In August 2015, the FASB issued a one-year deferral in the effective date. Since the issuance of ASU No. 2014-09, the FASB also has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. The Company must adopt ASU 2014-09 beginning on January 1, 2018. Early adoption would be permitted beginning January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method although it is unlikely the Company would elect to early adopt the new standard. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures, but has not determined the effect of the standard on its financial reporting.

Accounting Standards Update 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

In August 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company anticipates adopting this standard as of December 31, 2016. The Company is 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 2016-01 – 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. The new standard will be effective for the Company beginning on January 1, 2018. Early adoption of the standard is permitted. The Company is in the process of analyzing the impacts of this new standard.

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. The new standard will be effective for the Company beginning on January 1, 2019. Early adoption of the standard is permitted. At adoption of the ASU, leases will be recognized and measured as of the earliest period presented using a modified retrospective approach. The Company is in the process of analyzing the impacts of this new standard.

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

In March 2016, the FASB issued ASU No. 2016-09. The ASU simplifies several aspects of the accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Currently, tax benefits resulting from deductions in excess of compensation cost on vested restricted stock and performance awards and on exercised stock options (“excess tax benefits”) are recorded to equity provided these benefits reduce taxes payable. Tax deficiencies resulting from deductions related to awards, which are below realized compensation cost upon vesting and on canceled stock options are recorded to equity. The Company has not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. Upon implementation of the new standard, the Company will record a cumulative effect adjustment to recognize excess tax benefits that have not been recorded due to the Company’s net operating loss. Subsequent to implementation, all excess tax benefits and deficiencies will be recorded to tax expense on the Condensed Consolidated Income Statements and classified as cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. The Company continues its process of analyzing the impacts of this new standard, but does not believe there will be any retrospective impacts to its financial statements. The Company anticipates adopting the new standard upon its required effective date of January 1, 2017.

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. The new standard is effective for the Company beginning on January 1, 2018.  Early adoption is permitted including adoption in an interim period.   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.

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)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Computation of Earnings Per Share

Information regarding the computation of earnings per share is as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	54,418	$	61,045	$	92,040	$	107,058
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	96		100		99		103
Average Shares – Basic	79,750		79,754		79,753		79,757
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	367		362		377		377
Average Shares – Diluted	80,117		80,116		80,130		80,134
Net Earnings Per Share of Common Stock:
Basic	$	0.68	$	0.77	$	1.15	$	1.34
Diluted	$	0.68	$	0.76	$	1.15	$	1.34

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2016

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 September 30, 2016
Electric operating revenues	$	311,276		$	89,098		$	—		$	400,374
Cost of energy	88,565			20,201			—			108,766
Utility margin	222,711			68,897			—			291,608
Other operating expenses	109,342			24,184			(3,006		)	130,520
Depreciation and amortization	33,312			16,354			3,351			53,017
Operating income (loss)	80,057			28,359			(345		)	108,071
Interest income	1,509			—			3,095			4,604
Other income (deductions)	4,980			855			(184		)	5,651
Interest charges	(22,213		)	(7,308		)	(2,946		)	(32,467		)
Segment earnings (loss) before income taxes	64,333			21,906			(380		)	85,859
Income taxes (benefit)	19,343			8,053			(93		)	27,303
Segment earnings (loss)	44,990			13,853			(287		)	58,556
Valencia non-controlling interest	(4,006		)	—			—			(4,006		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	40,852		$	13,853		$	(287	)	$	54,418
Nine Months Ended September 30, 2016
Electric operating revenues	$	780,228		$	246,498		$	—		$	1,026,726
Cost of energy	222,376			60,122			—			282,498
Utility margin	557,852			186,376			—			744,228
Other operating expenses	314,961			70,328			(9,261		)	376,028
Depreciation and amortization	97,778			45,760			10,263			153,801
Operating income (loss)	145,113			70,288			(1,002		)	214,399
Interest income	8,549			—			9,871			18,420
Other income (deductions)	17,305			2,139			(1,517		)	17,927
Interest charges	(66,494		)	(22,150		)	(8,535		)	(97,179		)
Segment earnings (loss) before income taxes	104,473			50,277			(1,183		)	153,567
Income taxes (benefit)	32,131			18,460			(497		)	50,094
Segment earnings (loss)	72,342			31,817			(686		)	103,473
Valencia non-controlling interest	(11,037		)	—			—			(11,037		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	60,909		$	31,817		$	(686	)	$	92,040
At September 30, 2016:
Total Assets	$	4,799,012		$	1,366,840		$	237,818		$	6,403,670
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2015
Electric operating revenues	$	333,437		$	83,996		$	—		$	417,433
Cost of energy	105,708			18,547			—			124,255
Utility margin	227,729			65,449			—			293,178
Other operating expenses	104,977			22,766			(3,573		)	124,170
Depreciation and amortization	29,042			15,016			3,445			47,503
Operating income	93,710			27,667			128			121,505
Interest income	1,152			—			(1		)	1,151
Other income (deductions)	5,289			672			(482		)	5,479
Interest charges	(19,837		)	(6,855		)	(836		)	(27,528		)
Segment earnings (loss) before income taxes	80,314			21,484			(1,191		)	100,607
Income taxes (benefit)	27,258			7,795			699			35,752
Segment earnings (loss)	53,056			13,689			(1,890		)	64,855
Valencia non-controlling interest	(3,678		)	—			—			(3,678		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	49,246		$	13,689		$	(1,890	)	$	61,045
Nine Months Ended September 30, 2015
Electric operating revenues	$	870,826		$	232,361		$	—		$	1,103,187
Cost of energy	299,302			54,637			—			353,939
Utility margin	571,524			177,724			—			749,248
Other operating expenses	312,534			65,332			(11,118		)	366,748
Depreciation and amortization	86,446			42,065			10,502			139,013
Operating income	172,544			70,327			616			243,487
Interest income	4,869			—			(27		)	4,842
Other income (deductions)	18,547			2,757			(2,935		)	18,369
Interest charges	(59,477		)	(20,636		)	(6,601		)	(86,714		)
Segment earnings (loss) before income taxes	136,483			52,448			(8,947		)	179,984
Income taxes (benefit)	44,560			19,200			(2,139		)	61,621
Segment earnings (loss)	91,923			33,248			(6,808		)	118,363
Valencia non-controlling interest	(10,909		)	—			—			(10,909		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	80,618		$	33,248		$	(6,808	)	$	107,058
At September 30, 2015:
Total Assets	$	4,615,442		$	1,282,766		$	114,374		$	6,012,582
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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Accumulated Other Comprehensive Income (Loss) (Tables)

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2016 and 2015 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, 2015	$	17,346		$	(88,822	)	$	(71,476	)	$	44		$	(71,432	)
Amounts reclassified from AOCI (pre-tax)	(10,135		)	4,128			(6,007		)	573			(5,434		)
Income tax impact of amounts reclassified	3,955			(1,611		)	2,344			(224		)	2,120
Other OCI changes (pre-tax)	3,115			—			3,115			(1,305		)	1,810
Income tax impact of other OCI changes	(1,216		)	—			(1,216		)	509			(707		)
Net change after income taxes	(4,281		)	2,517			(1,764		)	(447		)	(2,211		)
Balance at September 30, 2016	$	13,065		$	(86,305	)	$	(73,240	)	$	(403	)	$	(73,643	)

Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—		$	(61,755	)
Amounts reclassified from AOCI (pre-tax)	(22,552		)	4,464			(18,088		)	—			(18,088		)
Income tax impact of amounts reclassified	8,838			(1,749		)	7,089			—			7,089
Other OCI changes (pre-tax)	3,095			—			3,095			(704		)	2,391
Income tax impact of other OCI changes	(1,213		)	—			(1,213		)	276			(937		)
Net change after income taxes	(11,832		)	2,715			(9,117		)	(428		)	(9,545		)
Balance at September 30, 2015	$	16,176		$	(87,048	)	$	(70,872	)	$	(428	)	$	(71,300	)

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Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2016

Variable Interest Entities [Abstract]

Summarized Financial Information

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(In thousands)
Operating revenues	$	5,356		$	5,182		$	15,541		$	15,337
Operating expenses	(1,350		)	(1,504		)	(4,504		)	(4,428		)
Earnings attributable to non-controlling interest	$	4,006		$	3,678		$	11,037		$	10,909

Financial Position

	September 30,		December 31,
	2016		2015
	(In thousands)
Current assets	$	3,506	$	2,588
Net property, plant, and equipment	67,656		69,784
Total assets	71,162		72,372
Current liabilities	1,045		965
Owners’ equity – non-controlling interest	$	70,117	$	71,407

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Fair Value of Derivative and Other Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2016

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
	September 30, 2016			December 31, 2015
PNMR and PNM	(In thousands)
Current assets	$	3,949		$	3,813
Deferred charges	747			2,622
	4,696			6,435
Current liabilities	(2,423		)	(1,859		)
Long-term liabilities	(58		)	—
	(2,481		)	(1,859		)
Net	$	2,215		$	4,576

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						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
PNMR and PNM	(In thousands)
Electric operating revenues	$	1,652		$	6,823		$	214		$	7,354
Cost of energy	(1		)	(78		)	(1,113		)	(227		)
Total gain (loss)	$	1,651		$	6,745		$	(899	)	$	7,127

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
September 30, 2016	200,000	(2,924,985	)
December 31, 2015	577,481	(3,405,843	)

Schedule of Collateral Related to Derivative

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

Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
PNMR and PNM
September 30, 2016	$	—	$	—	$	—
December 31, 2015	$	839	$	—	$	839

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.

	September 30, 2016				December 31, 2015
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	4,831	$	—	$	10,700
Equity securities:
Domestic value	8,345		63,666		11,610		44,505
Domestic growth	5,619		47,996		11,163		61,078
International and other	2,868		28,304		1,569		27,961
Fixed income securities:
U.S. Government	696		37,152		178		27,880
Municipals	2,490		52,459		3,672		58,576
Corporate and other	1,698		36,627		628		28,342
	$	21,716	$	271,035	$	28,820	$	259,042

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 change in realized impairment losses of $0.1 million and $1.0 million for the three and nine months ended September 30, 2016 and $(2.4) million and $(3.2) million for the three and nine months ended September 30, 2015.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In thousands)
Proceeds from sales	$	86,975		$	71,576		$	280,989		$	166,097
Gross realized gains	$	7,026		$	8,998		$	27,273		$	22,463
Gross realized (losses)	$	(2,565	)	$	(4,014	)	$	(12,913	)	$	(7,133	)

Investments Classified by Contractual Maturity Date

At September 30, 2016, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR
	(In thousands)
Within 1 year	$	4,349	$	—
After 1 year through 5 years	36,265		119,987
After 5 years through 10 years	24,512		—
After 10 years through 15 years	10,286		—
After 15 years through 20 years	9,446		—
After 20 years	41,380		—
	$	126,238	$	119,987

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 September 30, 2016 and December 31, 2015 for items recorded at fair value.

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2016	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	4,831		$	4,831	$	—
Equity securities:
Domestic value	63,666			63,666		—
Domestic growth	47,996			47,996		—
International and other	28,304			28,304		—
Fixed income securities:
U.S. Government	37,152			35,879		1,273
Municipals	52,459			—		52,459
Corporate and other	36,627			6,849		29,778
	$	271,035		$	187,525	$	83,510
Commodity derivative assets	$	4,696		$	—	$	4,696
Commodity derivative liabilities	(2,481		)	—		(2,481		)
Net	$	2,215		$	—	$	2,215
December 31, 2015
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	10,700		$	10,700	$	—
Equity securities:
Domestic value	44,505			44,505		—
Domestic growth	61,078			61,078		—
International and other	27,961			27,961		—
Fixed income securities:
U.S. Government	27,880			26,608		1,272
Municipals	58,576			—		58,576
Corporate and other	28,342			6,500		21,842
	$	259,042		$	177,352	$	81,690
Commodity derivative assets	$	6,435		$	—	$	6,435
Commodity derivative liabilities	(1,859		)	—		(1,859		)
Net	$	4,576		$	—	$	4,576

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
September 30, 2016	(In thousands)
PNMR
Long-term debt	$	2,308,340	$	2,508,344	$	—	$	2,508,344	$	—
Westmoreland Loan	$	109,783	$	119,987	$	—	$	—	$	119,987
Other investments	$	428	$	1,030	$	428	$	—	$	602
PNM
Long-term debt	$	1,631,587	$	1,768,115	$	—	$	1,768,115	$	—
Other investments	$	197	$	197	$	197	$	—	$	—
TNMP
Long-term debt	$	420,802	$	482,385	$	—	$	482,385	$	—
Other investments	$	231	$	231	$	231	$	—	$	—
December 31, 2015
PNMR
Long-term debt	$	2,091,948	$	2,264,869	$	—	$	2,264,869	$	—
Investment in PVNGS lessor notes	$	8,587	$	8,947	$	—	$	—	$	8,947
Other investments	$	604	$	1,269	$	604	$	—	$	665
PNM
Long-term debt	$	1,580,677	$	1,703,209	$	—	$	1,703,209	$	—
Investment in PVNGS lessor notes	$	8,587	$	8,947	$	—	$	—	$	8,947
Other investments	$	366	$	366	$	366	$	—	$	—
TNMP
Long-term debt	$	361,411	$	411,661	$	—	$	411,661	$	—
Other investments	$	238	$	238	$	238	$	—	$	—

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Activity

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

	Nine Months Ended September 30,
Restricted Shares and Performance Based Shares	2016			2015
Expected quarterly dividends per share	$	0.22		$	0.20
Risk-free interest rate	0.94		%	0.92		%
Market-Based Shares
Dividend yield	2.74		%	2.87		%
Expected volatility	20.44		%	18.73		%
Risk-free interest rate	0.97		%	1.00		%

The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the nine months endedSeptember 30, 2016:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2015	245,094		$	24.81	569,342		$	19.35
Granted	190,276		$	26.49	—		$	—
Exercised	(213,812	)	$	23.44	(241,468	)	$	27.61
Forfeited	(714	)	$	29.54	(2,000	)	$	12.22
Expired	—		$	—	(8,200	)	$	24.85
Outstanding at September 30, 2016	220,844		$	27.58	317,674		$	12.97

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

	Nine Months Ended September 30,
Restricted Stock	2016		2015
Weighted-average grant date fair value	$	26.49	$	20.34
Total fair value of restricted shares that vested (in thousands)	$	5,011	$	6,503
Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	—
Total intrinsic value of options exercised (in thousands)	$	1,208	$	1,814

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Financing (Tables)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Schedule of Short-term Debt

Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2016		2015
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	22,400	$	—
PNM New Mexico Credit Facility	20,000		—
TNMP Revolving Credit Facility	—		59,000
PNMR:
PNMR Revolving Credit Facility	163,500		41,600
PNMR Term Loan Agreement	150,000		150,000
	$	355,900	$	250,600

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Pension and Other Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2016

Public Service Company of New Mexico [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs

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

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	35		$	51		$	—	$	—
Interest cost	7,577			7,064			1,087			1,022			203		190
Expected return on plan assets	(8,854		)	(9,831		)	(1,371		)	(1,403		)	—		—
Amortization of net (gain) loss	3,455			3,705			286			491			64		81
Amortization of prior service cost	(241		)	(241		)	(7		)	(160		)	—		—
Net periodic benefit cost	$	1,937		$	697		$	30		$	1		$	267	$	271
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost
Service cost	$	—		$	—		$	105		$	153		$	—	$	—
Interest cost	22,731			21,191			3,260			3,067			609		570
Expected return on plan assets	(26,562		)	(29,492		)	(4,113		)	(4,208		)	—		—
Amortization of net (gain) loss	10,365			11,115			858			1,474			192		243
Amortization of prior service cost	(724		)	(724		)	(22		)	(481		)	—		—
Net periodic benefit cost	$	5,810		$	2,090		$	88		$	5		$	801	$	813

Texas-New Mexico Power Company [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs

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

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	—		$	—		$	46		$	62		$	—	$	—
Interest cost	826			761			169			152			10		9
Expected return on plan assets	(986		)	(1,105		)	(122		)	(130		)	—		—
Amortization of net (gain) loss	175			195			(10		)	—			1		1
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost (Income)	$	15		$	(149	)	$	83		$	84		$	11	$	10
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2016			2015			2016			2015			2016		2015
	(In thousands)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	—		$	—		$	139		$	185		$	—	$	—
Interest cost	2,478			2,282			508			456			30		27
Expected return on plan assets	(2,957		)	(3,315		)	(367		)	(390		)	—		—
Amortization of net (gain) loss	525			586			(30		)	—			1		3
Amortization of prior service cost	—			—			—			—			—		—
Net Periodic Benefit Cost (Income)	$	46		$	(447	)	$	250		$	251		$	31	$	30

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Regulatory and Rate Matters (Tables)

9 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

Schedule of Rate Increases for Transmission Costs

The following sets forth TNMP’s recent interim transmission cost rate increases:

Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 8, 2014	$	25.2	$	4.2
March 16, 2015	27.1		4.4
September 10, 2015	7.0		1.4
March 23, 2016	25.8		4.3
September 8, 2016	9.5		1.8

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2016

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				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In thousands)
Services billings:
PNMR to PNM	$	22,189	$	21,894	$	67,192	$	65,961
PNMR to TNMP	6,593		6,707		20,881		20,366
PNM to TNMP	105		136		347		424
TNMP to PNMR	10		—		30		—
Interest billings:
PNMR to TNMP	13		34		112		167
PNMR to PNM	3		10		8		38
PNM to PNMR	38		24		110		79
Income tax sharing payments:
PNMR to PNM	—		—		—		1,450
PNMR to TNMP	—		—		—		—

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Significant Accounting Policies and Responsibility for Financial Statements (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended				3 Months Ended		9 Months Ended
	Sep. 30, 2016	Jul. 31, 2016	Sep. 30, 2015	Jul. 31, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Dividends Payable [Line Items]
Dividends declared on common stock (in dollars per share)	$ 0.22	$ 0.22	$ 0.200	$ 0.20	$ 0.22	$ 0.200	$ 0.66	$ 0.600
Dividends declared on common stock							$ 52,571
Public Service Company of New Mexico [Member]
Dividends Payable [Line Items]
Equity contribution from parent							28,142
Dividends declared on common stock							4,142	$ 46,200
Texas-New Mexico Power Company [Member]
Dividends Payable [Line Items]
Equity contribution from parent							50,000
Dividends declared on common stock							17,965	$ 19,600
Common Stock [Member] | Public Service Company of New Mexico [Member]
Dividends Payable [Line Items]
Equity contribution from parent							28,142
Common Stock [Member] | Texas-New Mexico Power Company [Member]
Dividends Payable [Line Items]
Equity contribution from parent							0
Paid-in Capital [Member] | Texas-New Mexico Power Company [Member]
Dividends Payable [Line Items]
Equity contribution from parent							$ 50,000

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net Earnings Attributable to PNMR	$ 54,418	$ 61,045	$ 92,040	$ 107,058
Average Number of Common Shares:
Outstanding during period (in shares)	79,654	79,654	79,654	79,654
Vested awards of restricted stock (in shares)	96	100	99	103
Average Shares – Basic (in shares)	79,750	79,754	79,753	79,757
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock (in shares)	367	362	377	377
Average Shares – Diluted (in shares)	80,117	80,116	80,130	80,134
Net Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 0.68	$ 0.77	$ 1.15	$ 1.34
Diluted (in dollars per share)	$ 0.68	$ 0.76	$ 1.15	$ 1.34

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Segment Information - Summarized Financial Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	$ 400,374	$ 417,433	$ 1,026,726	$ 1,103,187
Cost of energy	108,766	124,255	282,498	353,939
Utility margin	291,608	293,178	744,228	749,248
Other operating expenses	130,520	124,170	376,028	366,748
Depreciation and amortization	53,017	47,503	153,801	139,013
Operating income	108,071	121,505	214,399	243,487
Interest income	4,604	1,151	18,420	4,842
Other income (deductions)	5,651	5,479	17,927	18,369
Interest charges	(32,467)	(27,528)	(97,179)	(86,714)
Earnings before Income Taxes	85,859	100,607	153,567	179,984
Income taxes (benefit)	27,303	35,752	50,094	61,621
Net Earnings	58,556	64,855	103,473	118,363
Valencia non-controlling interest	(4,006)	(3,678)	(11,037)	(10,909)
Subsidiary preferred stock dividends	(132)	(132)	(396)	(396)
Net Earnings Available for PNM Common Stock	54,418	61,045	92,040	107,058
Total Assets	6,403,670	6,012,582	6,403,670	6,012,582	$ 6,009,328
Goodwill	278,297	278,297	278,297	278,297	$ 278,297
Public Service Company of New Mexico [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	311,276	333,437	780,228	870,826
Cost of energy	88,565	105,708	222,376	299,302
Utility margin	222,711	227,729	557,852	571,524
Other operating expenses	109,342	104,977	314,961	312,534
Depreciation and amortization	33,312	29,042	97,778	86,446
Operating income	80,057	93,710	145,113	172,544
Interest income	1,509	1,152	8,549	4,869
Other income (deductions)	4,980	5,289	17,305	18,547
Interest charges	(22,213)	(19,837)	(66,494)	(59,477)
Earnings before Income Taxes	64,333	80,314	104,473	136,483
Income taxes (benefit)	19,343	27,258	32,131	44,560
Net Earnings	44,990	53,056	72,342	91,923
Valencia non-controlling interest	(4,006)	(3,678)	(11,037)	(10,909)
Subsidiary preferred stock dividends	(132)	(132)	(396)	(396)
Net Earnings Available for PNM Common Stock	40,852	49,246	60,909	80,618
Total Assets	4,799,012	4,615,442	4,799,012	4,615,442
Goodwill	51,632	51,632	51,632	51,632
Texas-New Mexico Power Company [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	89,098	83,996	246,498	232,361
Cost of energy	20,201	18,547	60,122	54,637
Utility margin	68,897	65,449	186,376	177,724
Other operating expenses	24,184	22,766	70,328	65,332
Depreciation and amortization	16,354	15,016	45,760	42,065
Operating income	28,359	27,667	70,288	70,327
Interest income	0	0	0	0
Other income (deductions)	855	672	2,139	2,757
Interest charges	(7,308)	(6,855)	(22,150)	(20,636)
Earnings before Income Taxes	21,906	21,484	50,277	52,448
Income taxes (benefit)	8,053	7,795	18,460	19,200
Net Earnings	13,853	13,689	31,817	33,248
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings Available for PNM Common Stock	13,853	13,689	31,817	33,248
Total Assets	1,366,840	1,282,766	1,366,840	1,282,766
Goodwill	226,665	226,665	226,665	226,665
Corporate and Other [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	0	0	0	0
Cost of energy	0	0	0	0
Utility margin	0	0	0	0
Other operating expenses	(3,006)	(3,573)	(9,261)	(11,118)
Depreciation and amortization	3,351	3,445	10,263	10,502
Operating income	(345)	128	(1,002)	616
Interest income	3,095	(1)	9,871	(27)
Other income (deductions)	(184)	(482)	(1,517)	(2,935)
Interest charges	(2,946)	(836)	(8,535)	(6,601)
Earnings before Income Taxes	(380)	(1,191)	(1,183)	(8,947)
Income taxes (benefit)	(93)	699	(497)	(2,139)
Net Earnings	(287)	(1,890)	(686)	(6,808)
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings Available for PNM Common Stock	(287)	(1,890)	(686)	(6,808)
Total Assets	237,818	114,374	237,818	114,374
Goodwill	$ 0	$ 0	$ 0	$ 0

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Segment Information - Narrative (Details) - Adjustments for New Accounting Pronouncement [Member] $ in Millions	9 Months Ended
	Sep. 30, 2015 USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Previously reported amounts reclassified	$ 40.3
Public Service Company of New Mexico [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Previously reported amounts reclassified	22.1
Texas-New Mexico Power Company [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Previously reported amounts reclassified	$ 10.4

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Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Equity [Abstract]
Percentage of pension liability adjustment capitalized into construction work In process			24.30%	22.40%
Percentage of pension liability adjustment capitalized into other accounts			2.50%	2.50%
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			$ (71,432)
Total Other Comprehensive Income (Loss)	$ 1,063	$ (7,475)	(2,211)	$ (9,545)
Ending Balance	(73,643)		(73,643)
Public Service Company of New Mexico [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(71,476)	(61,755)
Amounts reclassified from AOCI (pre-tax)			(6,007)	(18,088)
Income tax impact of amounts reclassified			2,344	7,089
Other OCI changes (pre-tax)			3,115	3,095
Income tax impact of other OCI changes			(1,216)	(1,213)
Total Other Comprehensive Income (Loss)	671	(7,047)	(1,764)	(9,117)
Ending Balance	(73,240)	(70,872)	(73,240)	(70,872)
Public Service Company of New Mexico [Member] | Unrealized Gains on Available-for-Sale Securities [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			17,346	28,008
Amounts reclassified from AOCI (pre-tax)			(10,135)	(22,552)
Income tax impact of amounts reclassified			3,955	8,838
Other OCI changes (pre-tax)			3,115	3,095
Income tax impact of other OCI changes			(1,216)	(1,213)
Total Other Comprehensive Income (Loss)			(4,281)	(11,832)
Ending Balance	13,065	16,176	13,065	16,176
Public Service Company of New Mexico [Member] | Pension Liability Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(88,822)	(89,763)
Amounts reclassified from AOCI (pre-tax)			4,128	4,464
Income tax impact of amounts reclassified			(1,611)	(1,749)
Total Other Comprehensive Income (Loss)			2,517	2,715
Ending Balance	(86,305)	(87,048)	(86,305)	(87,048)
PNMR [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(71,432)	(61,755)
Amounts reclassified from AOCI (pre-tax)			(5,434)	(18,088)
Income tax impact of amounts reclassified			2,120	7,089
Other OCI changes (pre-tax)			1,810	2,391
Income tax impact of other OCI changes			(707)	(937)
Total Other Comprehensive Income (Loss)			(2,211)	(9,545)
Ending Balance	(73,643)	(71,300)	(73,643)	(71,300)
PNMR [Member] | Fair Value Adjustment for Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			44
Amounts reclassified from AOCI (pre-tax)			573
Income tax impact of amounts reclassified			(224)
Other OCI changes (pre-tax)			(1,305)	(704)
Income tax impact of other OCI changes			509	276
Total Other Comprehensive Income (Loss)			(447)	(428)
Ending Balance	$ (403)	$ (428)	$ (403)	$ (428)

XML

Variable Interest Entities (Details)				3 Months Ended		9 Months Ended
	Jan. 31, 2016 USD ($) MW	May 30, 2014	Oct. 08, 2013 USD ($)	Sep. 30, 2016 USD ($) MW	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) MW	Sep. 30, 2015 USD ($)	Nov. 01, 2016 USD ($)	Oct. 21, 2016 USD ($)	Aug. 31, 2016 USD ($)	Aug. 30, 2016 USD ($)	Aug. 01, 2016 USD ($)	Jul. 19, 2016 USD ($)	Jan. 15, 2016 lease MW	Dec. 31, 2015 USD ($)	Jan. 15, 2015 lease
Results of Operations
Earnings attributable to non-controlling interest				$ 4,006,000	$ 3,678,000	$ 11,037,000	$ 10,909,000
Financial Position
Current assets				398,886,000		398,886,000									$ 385,570,000
Total assets				6,403,670,000	6,012,582,000	6,403,670,000	6,012,582,000								6,009,328,000
Current liabilities				701,826,000		701,826,000									641,120,000
Owners’ equity – non-controlling interest				70,117,000		70,117,000									71,407,000
Public Service Company of New Mexico [Member]
Results of Operations
Earnings attributable to non-controlling interest				4,006,000	3,678,000	11,037,000	10,909,000
Financial Position
Current assets				310,645,000		310,645,000									357,757,000
Total assets				4,799,012,000		4,799,012,000									4,599,344,000
Current liabilities				275,983,000		275,983,000									316,921,000
Owners’ equity – non-controlling interest				70,117,000		70,117,000									71,407,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member]
Variable Interest Entity [Line Items]
Other financial obligations due to beneficial owner				0		0
Recourse available for creditors of trusts other than contractual lease payments				0		0
Additional rights to assets beyond use of leased assets				0		0
Assets related to the trusts other than accrued lease payments				0		0									0
Liabilities related to the trusts other than accrued lease payments				0		0									0
Accrued lease payments				3,800,000		3,800,000									18,400,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 1 Leases [Member]
Variable Interest Entity [Line Items]
Number of leases, expiring | lease																4
Number of leases under which lease term was extended | lease																4
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases [Member]
Variable Interest Entity [Line Items]
Number of megawatts purchased (in megawatts) | MW	64.1													64.1
Number of leases, expiring | lease														4
Number of leases under which lease term was extended | lease														1
Number of leases under which assets were purchased | lease														3
Public Service Company of New Mexico [Member] | Valencia [Member]
Variable Interest Entity [Line Items]
Payment for fixed costs				4,900,000	4,900,000	14,500,000	14,500,000
Payment for variable costs				500,000	300,000	$ 1,100,000	900,000
Long-term contract option to purchase, ownership percentage		50.00%	50.00%			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%
Long-term contract option to purchase, number of days to set FMV						60 days
Long-term contract option to purchase, estimated purchase price			$ 85,000,000
Long-term contract option to purchase, approximate approval period						15 months
Results of Operations
Operating revenues				5,356,000	5,182,000	$ 15,541,000	15,337,000
Operating expenses				(1,350,000)	(1,504,000)	(4,504,000)	(4,428,000)
Earnings attributable to non-controlling interest				4,006,000	$ 3,678,000	11,037,000	$ 10,909,000
Financial Position
Current assets				3,506,000		3,506,000									2,588,000
Net property, plant, and equipment				67,656,000		67,656,000									69,784,000
Total assets				71,162,000		71,162,000									72,372,000
Current liabilities				1,045,000		1,045,000									965,000
Owners’ equity – non-controlling interest				$ 70,117,000		$ 70,117,000									71,407,000
Public Service Company of New Mexico [Member] | Valencia [Member] | Purchased Through May 30, 2028 [Member]
Variable Interest Entity [Line Items]
Number of megawatts purchased (in megawatts) | MW				158		158
NM Capital [Member] | San Juan Generating Station [Member] | Coal Supply [Member]
Variable Interest Entity [Line Items]
Loan agreement among several entities	$ 125,000,000
Cash used to support bank letter or credit arrangement													$ 30,300,000		$ 40,000,000
NM Capital [Member] | San Juan Coal Company, Westmoreland [Member] | Coal Supply [Member]
Variable Interest Entity [Line Items]
Cash used to support bank letter or credit arrangement										$ 30,300,000	$ 40,000,000
Loan receivable	$ 125,000,000			$ 110,000,000		$ 110,000,000
Scheduled principal payment proceeds												$ 15,000,000
Interest receivable				$ 1,500,000		$ 1,500,000
NM Capital [Member] | San Juan Coal Company, Westmoreland [Member] | Coal Supply [Member] | Subsequent event [Member]
Variable Interest Entity [Line Items]
Scheduled principal payment proceeds								$ 15,000,000
Scheduled interest payment proceeds								$ 2,300,000
Unaffiliated third party [Member] | San Juan Coal Company, Westmoreland [Member] | Coal Supply [Member] | Subsequent event [Member]
Variable Interest Entity [Line Items]
Amount held in a restricted bank account									$ 17,300,000

XML

Lease Commitments (Details) - Public Service Company of New Mexico [Member] $ in Millions	Jan. 15, 2016 USD ($) lease MW	Mar. 31, 2015	Sep. 30, 2016 USD ($)	Apr. 01, 2015 USD ($)	Jan. 15, 2015 lease
Operating Leased Assets [Line Items]
Ownership of the EIP		60.00%
Percent leased, now expired		40.00%
Leased capacity at fair market value, elected to purchase | $				$ 7.7
Palo Verde Nuclear Generating Station, Unit 1 Leases [Member]
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 [Member]
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
Leased capacity to be purchased (in megawatts) | MW	32.76
Palo Verde Nuclear Generating Station, Unit 2 Leases, 31.25 MW [Member]
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 [Member]
Operating Leased Assets [Line Items]
Leased capacity to be purchased (in megawatts) | MW	31.2494
Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]
Operating Leased Assets [Line Items]
Number of leases under which assets were purchased	2
Payment to lessors | $	$ 85.2
Palo Verde Nuclear Generating Station [Member]
Operating Leased Assets [Line Items]
Loss contingency, lease arrangements | $			$ 176.1

XML

Fair Value of Derivative and Other Financial Instruments - Commodity Derivatives (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Current assets	$ 3,949,000	$ 3,813,000
Deferred charges	747,000	2,622,000
Current liabilities	(2,423,000)	(1,859,000)
Long-term liabilities	(58,000)	0
PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Amounts recognized for the right to reclaim cash collateral	0	0
Amounts posted as cash collateral under margin arrangements	3,000,000	2,700,000
Obligations to return cash collateral	100,000	100,000
PNMR and PNM [Member] | Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Current assets	3,949,000	3,813,000
Deferred charges	747,000	2,622,000
Commodity derivative instruments, Assets	4,696,000	6,435,000
Current liabilities	(2,423,000)	(1,859,000)
Long-term liabilities	(58,000)	0
Commodity derivative instruments, Liabilities	(2,481,000)	(1,859,000)
Net	2,215,000	4,576,000
PNMR and PNM [Member] | Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Palo Verde Nuclear Generating Station [Member]
Derivatives, Fair Value [Line Items]
Current assets	2,700,000	3,000,000
Deferred charges	600,000	2,600,000
Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Current assets	3,949,000	3,813,000
Deferred charges	747,000	2,622,000
Current liabilities	(2,423,000)	(1,859,000)
Long-term liabilities	(58,000)	0
Public Service Company of New Mexico [Member] | Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Fuel and Purchased Power Adjustment Clause [Member]
Derivatives, Fair Value [Line Items]
Current assets	100,000	400,000
Deferred charges	100,000
Current liabilities	$ (100,000)	$ (200,000)

XML

Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - Designated as Hedging Instrument [Member] - Commodity Contract [Member] - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 1,651	$ 6,745	$ (899)	$ 7,127
Electric operating revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	1,652	6,823	214	7,354
Cost of energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ (1)	$ (78)	$ (1,113)	$ (227)

XML

Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) - PNMR and PNM [Member] $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016 USD ($) MMBTU MWh	Dec. 31, 2015 USD ($) MMBTU MWh
Derivative [Line Items]
Contractual Liability	$ 0	$ 839
Existing Cash Collateral	0	0
Net Exposure	$ 0	$ 839
Commodity Contract [Member] | Fair Value Hedging [Member] | Buy [Member]
Derivative [Line Items]
Economic Hedges (in mmbtu and mwh) | MMBTU	200,000	577,481
Commodity Contract [Member] | Fair Value Hedging [Member] | Sell [Member]
Derivative [Line Items]
Economic Hedges (in mmbtu and mwh) | MWh	2,924,985	3,405,843

XML

Fair Value of Derivative and Other Financial Instruments - Sale of Power (Details)	Dec. 31, 2017 $ / MWh	Sep. 30, 2016 $ / MWh MW
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member]
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 [Member] | PNMR and PNM [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative, average forward price (in dollars per MWh)		26
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Commodity Contract [Member] | Subsequent event [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative, average forward price (in dollars per MWh)	29
Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member] | Firm Contract [Member]
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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
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	$ 100,000	$ (2,400,000)	$ 1,000,000	$ (3,200,000)
Available-for-sale securities for which carrying value exceeds fair value	0		0
Other than Temporary Impairment Losses, Investments, Portion in Other Comprehensive Loss, before Tax, Including Portion Attributable to Noncontrolling Interest			0
PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	271,035,000		271,035,000		$ 259,042,000
Unrealized Gains	21,716,000		21,716,000		28,820,000
Proceeds from sales	86,975,000	71,576,000	280,989,000	166,097,000
Gross realized gains	7,026,000	8,998,000	27,273,000	22,463,000
Gross realized (losses)	(2,565,000)	$ (4,014,000)	(12,913,000)	$ (7,133,000)
PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	271,035,000		271,035,000		259,042,000
PNMR and PNM [Member] | Nuclear Decommissioning Trust [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	258,600,000		258,600,000		249,100,000
PNMR and PNM [Member] | Mine Reclamation Trust [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	12,400,000		12,400,000		9,900,000
PNMR and PNM [Member] | Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	4,831,000		4,831,000		10,700,000
Unrealized Gains	0		0		0
PNMR and PNM [Member] | Cash and equivalents [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	4,831,000		4,831,000		10,700,000
PNMR and PNM [Member] | Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	63,666,000		63,666,000		44,505,000
Unrealized Gains	8,345,000		8,345,000		11,610,000
PNMR and PNM [Member] | Domestic value [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	63,666,000		63,666,000		44,505,000
PNMR and PNM [Member] | Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	47,996,000		47,996,000		61,078,000
Unrealized Gains	5,619,000		5,619,000		11,163,000
PNMR and PNM [Member] | Domestic growth [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	47,996,000		47,996,000		61,078,000
PNMR and PNM [Member] | International and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	28,304,000		28,304,000		27,961,000
Unrealized Gains	2,868,000		2,868,000		1,569,000
PNMR and PNM [Member] | International and other [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	28,304,000		28,304,000		27,961,000
PNMR and PNM [Member] | U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	37,152,000		37,152,000		27,880,000
Unrealized Gains	696,000		696,000		178,000
PNMR and PNM [Member] | U.S. Government [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	37,152,000		37,152,000		27,880,000
PNMR and PNM [Member] | Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	52,459,000		52,459,000		58,576,000
Unrealized Gains	2,490,000		2,490,000		3,672,000
PNMR and PNM [Member] | Municipals [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	52,459,000		52,459,000		58,576,000
PNMR and PNM [Member] | Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	36,627,000		36,627,000		28,342,000
Unrealized Gains	1,698,000		1,698,000		628,000
PNMR and PNM [Member] | Corporate and other [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	$ 36,627,000		$ 36,627,000		$ 28,342,000

XML

Fair Value of Derivative and Other Financial Instruments - Debt Maturities (Details)	9 Months Ended
	Sep. 30, 2016 USD ($)
Debt Maturities [Line Items]
Held-to-maturity Securities, Continuous Unrealized Loss Position, Fair Value	$ 0
Held-to-Maturity
Other than Temporary Impairment Losses, Investments, Portion in Other Comprehensive Loss, before Tax, Including Portion Attributable to Noncontrolling Interest	0
PNMR and PNM [Member]
Available-for-Sale
Within 1 year	4,349,000
After 1 year through 5 years	36,265,000
After 5 years through 10 years	24,512,000
After 10 years through 15 years	10,286,000
After 15 years through 20 years	9,446,000
After 20 years	41,380,000
Available-for-sale debt securities	126,238,000
PNM Resources [Member]
Held-to-Maturity
Within 1 year	0
After 1 year through 5 years	119,987,000
After 5 years through 10 years	0
Held-to-maturity debt securities	$ 119,987,000

XML

Fair Value of Derivative and Other Financial Instruments - Recurring (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 271,035	$ 259,042
PNMR and PNM [Member] | Cash and equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	4,831	10,700
PNMR and PNM [Member] | Domestic value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	63,666	44,505
PNMR and PNM [Member] | Domestic growth [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	47,996	61,078
PNMR and PNM [Member] | International and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	28,304	27,961
PNMR and PNM [Member] | U.S. Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	37,152	27,880
PNMR and PNM [Member] | Municipals [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	52,459	58,576
PNMR and PNM [Member] | Corporate and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	36,627	28,342
PNM Resources [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,508,344	2,264,869
Westmoreland Loan	119,987
Investment in PVNGS lessor notes		8,947
Other investments	1,030	1,269
PNM Resources [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Westmoreland Loan	0
Investment in PVNGS lessor notes		0
Other investments	428	604
PNM Resources [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,508,344	2,264,869
Westmoreland Loan	0
Investment in PVNGS lessor notes		0
Other investments	0	0
PNM Resources [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Westmoreland Loan	119,987
Investment in PVNGS lessor notes		8,947
Other investments	602	665
PNM Resources [Member] | Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,308,340	2,091,948
Westmoreland Loan	109,783
Investment in PVNGS lessor notes		8,587
Other investments	428	604
Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,768,115	1,703,209
Investment in PVNGS lessor notes		8,947
Other investments	197	366
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment in PVNGS lessor notes		0
Other investments	197	366
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,768,115	1,703,209
Investment in PVNGS lessor notes		0
Other investments	0	0
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment in PVNGS lessor notes		8,947
Other investments	0	0
Public Service Company of New Mexico [Member] | Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,631,587	1,580,677
Investment in PVNGS lessor notes		8,587
Other investments	197	366
Texas-New Mexico Power Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	482,385	411,661
Other investments	231	238
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	231	238
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	482,385	411,661
Other investments	0	0
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	0	0
Texas-New Mexico Power Company [Member] | Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	420,802	361,411
Other investments	231	238
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	271,035	259,042
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	187,525	177,352
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	83,510	81,690
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	4,696	6,435
Commodity derivative liabilities	(2,481)	(1,859)
Net	2,215	4,576
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Commodity Contract [Member] | Fair Value, Inputs, Level 1 [Member]
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 [Member] | PNMR and PNM [Member] | Commodity Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	4,696	6,435
Commodity derivative liabilities	(2,481)	(1,859)
Net	2,215	4,576
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Cash and equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	4,831	10,700
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Cash and equivalents [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	4,831	10,700
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Cash and equivalents [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	63,666	44,505
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic value [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	63,666	44,505
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic value [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic growth [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	47,996	61,078
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic growth [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	47,996	61,078
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic growth [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | International and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	28,304	27,961
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | International and other [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	28,304	27,961
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | International and other [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | U.S. Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	37,152	27,880
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | U.S. Government [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	35,879	26,608
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | U.S. Government [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,273	1,272
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Municipals [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	52,459	58,576
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Municipals [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Municipals [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	52,459	58,576
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Corporate and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	36,627	28,342
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Corporate and other [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	6,849	6,500
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Corporate and other [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 29,778	$ 21,842

XML

Stock-Based Compensation (Details) - USD ($)	9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Mar. 31, 2015	Feb. 28, 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
Unrecognized expense related to stock awards	$ 5,900,000		$ 5,700,000
Restricted Stock, Shares
Expired (in shares)	(8,200)
Restricted Stock, Weighted- Average Grant Date Fair Value
Expired (in dollars per share)	$ 24.85
Stock Options, Shares
Outstanding at beginning of period (in shares)	569,342
Granted (in shares)	0
Exercised (in shares)	(241,468)
Forfeited (in shares)	(2,000)
Expired (in shares)	(8,200)
Outstanding at end of period (in shares)	317,674		569,342
Stock Options, Weighted- Average Exercise Price
Outstanding at beginning of period (in dollars per share)	$ 19.35
Granted (in dollars per share)	0.00
Exercised (in dollars per share)	27.61
Forfeited (in dollars per share)	12.22
Expired (in dollars per share)	24.85
Outstanding at end of period (in dollars per share)	12.97		$ 19.35
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	$ 1,208,000	$ 1,814,000
Chairman, President, and Chief Executive Officer [Member] | Common Stock [Member] | Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee [Member]
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 [Member] | Common Stock [Member] | Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 and she remains an employee [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return (in shares)							35,000
Board approval for shares after specified target was reached (in shares)					35,000
Chairman, President, and Chief Executive Officer [Member] | Common Stock [Member] | Achieves a specific performance target by the end of 2019 and she remains an employee [Member]
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 [Member] | Common Stock [Member] | Achieves a specific performance target by the end of 2017 and she remains an employee [Member] [Member]
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 [Member] | Common Stock [Member] | Achieved performance target for 2015 and 2016 [Member]
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
Executive Vice President and Chief Financial Officer [Member] | Common Stock [Member] | Achieved performance target for 2015, 2016 and 2017 [Member]
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
Restricted Stock and Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period of time stock expense is expected to be recognized	1 year 11 months		1 year 4 months 24 days
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected quarterly dividends per share (in dollars per share)	$ 0.22	$ 0.20
Risk-free interest rate	0.94%	0.92%
Restricted Stock, Shares
Outstanding at beginning of period (in shares)	245,094
Granted (in shares)	190,276
Exercised (in shares)	(213,812)
Forfeited (in shares)	(714)
Expired (in shares)	0
Outstanding at end of period (in shares)	220,844		245,094
Restricted Stock, Weighted- Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 24.81
Granted (in dollars per share)	26.49	$ 20.34
Exercised (in dollars per share)	23.44
Forfeited (in dollars per share)	29.54
Expired (in dollars per share)	0.00
Outstanding at end of period (in dollars per share)	$ 27.58		$ 24.81
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)	$ 26.49	$ 20.34
Total fair value of restricted shares that vested	$ 5,011,000	$ 6,503,000
Performance Shares [Member] | Executive [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)	79,619
Shares exercised (in shares)	79,619
Share-based compensation, weighted percentage assigned to achieving market targets	60.00%
Share-based compensation, weighted percentage assigned to achieving performance targets	40.00%
Share-based compensation, maximum number of shares awarded in year 1 (in shares)	165,628
Share-based compensation, maximum number of shares awarded in year 2 (in shares)	166,797
Share-based compensation, maximum number of shares awarded in year 3 (in shares)	147,031
Performance period	3 years
Market-Based Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Risk-free interest rate	0.97%	1.00%
Dividend yield	2.74%	2.87%
Expected volatility	20.44%	18.73%
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of stock options outstanding	$ 6,300,000
Weighted-average remaining contract life	2 years 2 months 19 days
Number of outstanding stock options with an exercise price greater than the closing price (in shares)	0
Performance Equity Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Vesting rate	100.00%

XML

Financing - Financing Activities (Details)			1 Months Ended	9 Months Ended	12 Months Ended
	Nov. 01, 2016 USD ($)	Feb. 01, 2016 USD ($)	Jun. 21, 2016 USD ($)	Sep. 30, 2016 USD ($) covenant	Dec. 31, 2015 USD ($)	Oct. 21, 2016 USD ($)	Sep. 27, 2016 USD ($)	May 20, 2016 USD ($)	Dec. 17, 2015 USD ($)	Sep. 30, 2015	Mar. 09, 2015 USD ($)
Debt Instrument [Line Items]
Number of applicable financial covenants | covenant				1
Fixed interest rate										1.927%
Cash Flow Hedging [Member] | Fair Value, Inputs, Level 2 [Member]
Debt Instrument [Line Items]
Fair value gain (loss)				$ (700,000)	$ 100,000
Public Service Company of New Mexico [Member] | Maximum [Member]
Debt Instrument [Line Items]
Maturity term over which financings require regulator approval				18 months
NM Capital [Member] | Coal Supply [Member] | San Juan Generating Station [Member]
Debt Instrument [Line Items]
Payments to fund long-term loans to unaffiliated third party		$ 125,000,000.0
Line of Credit [Member]
Debt Instrument [Line Items]
Ratio of debt to capital (less than or equal to)				65.00%
PNMR 2015 Term Loan Agreement [Member]
Debt Instrument [Line Items]
Term loans											$ 150,000,000.0
Interest rate				1.42%
BTMU Term Loan Agreement [Member] | NM Capital [Member]
Debt Instrument [Line Items]
Term loans		$ 125,000,000.0		$ 107,800,000.0
Stated interest rate				3.51%
Estimated principal payments				$ 45,100,000
BTMU Term Loan Agreement [Member] | NM Capital [Member] | Minimum [Member] | Subsequent event [Member]
Debt Instrument [Line Items]
Long-term debt, required quarterly payment	$ 5,000,000.0
First Mortgage Bonds [Member] | Texas-New Mexico Power Company [Member] | First Mortgage Bonds, 3.53%, due 2026, Series 2016A [Member]
Debt Instrument [Line Items]
Stated interest rate									3.53%
Aggregate principal amount									$ 60,000,000.0
PNM 2016 Term Loan Agreement [Member] | Public Service Company of New Mexico [Member]
Debt Instrument [Line Items]
Stated interest rate				1.15%
Aggregate principal amount								$ 175,000,000.0
PNM 2014 Multi-Draw Term Loan Agreement [Member] | Public Service Company of New Mexico [Member]
Debt Instrument [Line Items]
Repayments of debt			$ 125,000,000
Pollution Control Bonds [Member] [Member] | Public Service Company of New Mexico [Member] | Pollution Control Revenue Bonds 1 Point 875 Percent, due 2021 [Member]
Debt Instrument [Line Items]
Stated interest rate							1.875%
Aggregate principal amount							$ 146,000,000.0
Pollution Control Bonds [Member] [Member] | Public Service Company of New Mexico [Member] | Pollution Control Revenue Bonds 1 Point 875 Percent, due 2021, 2016 Series A [Member]
Debt Instrument [Line Items]
Aggregate principal amount							46,000,000.0
Pollution Control Bonds [Member] [Member] | Public Service Company of New Mexico [Member] | Pollution Control Revenue Bonds 1 Point 875 Percent, due 2021, 2016 Series B [Member]
Debt Instrument [Line Items]
Aggregate principal amount							$ 100,000,000.0
Letter of Credit [Member] | PNMR [Member] | Subsequent event [Member] | Letter or credit, 30 mil JP Morgan [Member]
Debt Instrument [Line Items]
Aggregate principal amount						$ 30,300,000.0

XML

Financing - Short-term Debt (Details) - USD ($)	9 Months Ended
	Sep. 30, 2016	Oct. 21, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Short-term debt	$ 355,900,000		$ 250,600,000
Letters of credit outstanding	$ 36,500,000
Subsequent event [Member]
Short-term Debt [Line Items]
Remaining borrowing capacity		$ 592,800,000
PNMR Term Loan Agreement [Member]
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt	1.38%
Short-term debt	$ 150,000,000		150,000,000
Notes Payable to Banks [Member] | PNMR Term Loan Agreement [Member]
Short-term Debt [Line Items]
Term of loan	12 months
Borrowings under 12-month term loan	$ 150,000,000.0
PNM Resources [Member] | Subsequent event [Member]
Short-term Debt [Line Items]
Remaining borrowing capacity		100,400,000
Consolidated invested cash		1,800,000
PNM Resources [Member] | PNMR Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt	1.78%
PNM Resources [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Financing capacity	$ 300,000,000.0
Short-term debt	163,500,000		41,600,000
Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Short-term debt	42,400,000		0
Letters of credit outstanding	2,500,000
Public Service Company of New Mexico [Member] | Subsequent event [Member]
Short-term Debt [Line Items]
Remaining borrowing capacity		373,500,000
Consolidated invested cash		0
Public Service Company of New Mexico [Member] | Local Lines of Credit [Member]
Short-term Debt [Line Items]
NMPRC approved credit facility	$ 50,000,000
Weighted-average interest rate for short-term debt	1.68%
Short-term debt	$ 20,000,000		0
Public Service Company of New Mexico [Member] | Local Lines of Credit [Member] | Subsequent event [Member]
Short-term Debt [Line Items]
Remaining borrowing capacity		44,000,000
Public Service Company of New Mexico [Member] | PNMR Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt	1.66%
Public Service Company of New Mexico [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Financing capacity	$ 400,000,000.0
Short-term debt	22,400,000		0
Texas-New Mexico Power Company [Member]
Short-term Debt [Line Items]
Short-term debt	0		59,000,000
Letters of credit outstanding	100,000
Short-term debt – affiliate	0		11,800,000
Texas-New Mexico Power Company [Member] | Subsequent event [Member]
Short-term Debt [Line Items]
Remaining borrowing capacity		74,900,000
Consolidated invested cash		300,000
Texas-New Mexico Power Company [Member] | Subsequent event [Member] | Affiliated Entity [Member]
Short-term Debt [Line Items]
Short-term debt – affiliate		$ 0
Texas-New Mexico Power Company [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Financing capacity	75,000,000.0
Short-term debt	0		$ 59,000,000
Texas-New Mexico Power Company [Member] | Revolving Credit Facility [Member] | First Mortgage Bonds, Due 2014, Series 2009A, at 9.50% [Member]
Short-term Debt [Line Items]
Collateral amount	$ 75,000,000

XML

Pension and Other Postretirement Benefit Plans (Details) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Components of Net Periodic Benefit Cost
Service cost	$ 0	$ 0	$ 0	$ 0
Interest cost	7,577,000	7,064,000	22,731,000	21,191,000
Expected return on plan assets	(8,854,000)	(9,831,000)	(26,562,000)	(29,492,000)
Amortization of net (gain) loss	3,455,000	3,705,000	10,365,000	11,115,000
Amortization of prior service cost	(241,000)	(241,000)	(724,000)	(724,000)
Net Periodic Benefit Cost (Income)	1,937,000	697,000	5,810,000	2,090,000
Contributions by employer		0		30,000,000
Total expected employer contributions for fiscal year	0		0
Total expected employer contributions for future fiscal years	0		$ 0
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Minimum [Member]
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate			4.80%
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Maximum [Member]
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate			5.70%
Public Service Company of New Mexico [Member] | OPEB [Member]
Components of Net Periodic Benefit Cost
Service cost	35,000	51,000	$ 105,000	153,000
Interest cost	1,087,000	1,022,000	3,260,000	3,067,000
Expected return on plan assets	(1,371,000)	(1,403,000)	(4,113,000)	(4,208,000)
Amortization of net (gain) loss	286,000	491,000	858,000	1,474,000
Amortization of prior service cost	(7,000)	(160,000)	(22,000)	(481,000)
Net Periodic Benefit Cost (Income)	30,000	1,000	88,000	5,000
Contributions by employer	800,000	800,000	2,400,000	2,400,000
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Components of Net Periodic Benefit Cost
Service cost	0	0	0	0
Interest cost	203,000	190,000	609,000	570,000
Expected return on plan assets	0	0	0	0
Amortization of net (gain) loss	64,000	81,000	192,000	243,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	267,000	271,000	801,000	813,000
Contributions by employer	400,000	400,000	1,200,000	1,200,000
Total expected employer contributions for fiscal year	1,500,000		1,500,000
Total expected employer contributions for future fiscal years	5,900,000		5,900,000
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Components of Net Periodic Benefit Cost
Service cost	0	0	0	0
Interest cost	826,000	761,000	2,478,000	2,282,000
Expected return on plan assets	(986,000)	(1,105,000)	(2,957,000)	(3,315,000)
Amortization of net (gain) loss	175,000	195,000	525,000	586,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	15,000	(149,000)	46,000	(447,000)
Contributions by employer					$ 0
Total expected employer contributions for fiscal year	0		0
Total expected employer contributions for future fiscal years	0		$ 0
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Minimum [Member]
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate			4.80%
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Maximum [Member]
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate			5.70%
Texas-New Mexico Power Company [Member] | OPEB [Member]
Components of Net Periodic Benefit Cost
Service cost	46,000	62,000	$ 139,000	185,000
Interest cost	169,000	152,000	508,000	456,000
Expected return on plan assets	(122,000)	(130,000)	(367,000)	(390,000)
Amortization of net (gain) loss	(10,000)	0	(30,000)	0
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	83,000	84,000	250,000	251,000
Contributions by employer	0	0	0	0
Total expected employer contributions for fiscal year	300,000		300,000
Total expected employer contributions for future fiscal years	1,400,000		1,400,000
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Components of Net Periodic Benefit Cost
Service cost	0	0	0	0
Interest cost	10,000	9,000	30,000	27,000
Expected return on plan assets	0	0	0	0
Amortization of net (gain) loss	1,000	1,000	1,000	3,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	11,000	10,000	31,000	30,000
Total expected employer contributions for fiscal year	100,000		100,000
Total expected employer contributions for future fiscal years	400,000		400,000
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member] | Maximum [Member]
Components of Net Periodic Benefit Cost
Contributions by employer	$ 100,000	$ 100,000	$ 100,000	$ 100,000

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Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - Palo Verde Nuclear Generating Station [Member] - Public Service Company of New Mexico [Member] - USD ($)		3 Months Ended
	May 16, 2014	Mar. 31, 2015	Sep. 30, 2016	Dec. 31, 2015
Department of energy, spent nuclear fuel removal July 2011 - June 2014 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
PNM's share of third party settlement claim		$ 4,300,000
Litigation settlement, portion credited to customers		$ 3,100,000
Nuclear spent fuel and waste disposal [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss			$ 58,000,000
Revised annual fee, nuclear waste disposal	$ 0
Nuclear spent fuel and waste disposal [Member] | Other Deferred Credits [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual			$ 12,000,000	$ 12,200,000

XML

Commitments and Contingencies - The Clean Air Act (Details)				3 Months Ended			9 Months Ended		12 Months Ended	43 Months Ended
	Feb. 25, 2016	Dec. 16, 2015 USD ($) MWh MW	Mar. 02, 2015 lb / MMBTU T	Sep. 30, 2016 USD ($) joint_owner requirement well MW	Mar. 31, 2016 USD ($)	Sep. 30, 2015 USD ($) parts_per_billion	Sep. 30, 2016 USD ($) joint_owner requirement well MW	Sep. 30, 2015 USD ($) parts_per_billion	Dec. 31, 2015 USD ($)	Sep. 30, 2016 USD ($) joint_owner requirement well MW	Feb. 09, 2016	Jan. 26, 2016 state	Oct. 01, 2015 parts_per_billion	Jul. 31, 2015 MW	Dec. 30, 2013 lbsofnox / mmbtu	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				$ 16,451,000		$ 0	$ 17,225,000	$ 1,744,000
Plant in service, held for future use, and to be abandoned				6,842,017,000			6,842,017,000		$ 6,307,261,000	$ 6,842,017,000
Accumulated depreciation and amortization				2,312,560,000			2,312,560,000		2,058,772,000	2,312,560,000
Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs				16,451,000		$ 0	17,225,000	$ 1,744,000
Plant in service, held for future use, and to be abandoned				5,303,910,000			5,303,910,000		4,833,303,000	5,303,910,000
Accumulated depreciation and amortization				$ 1,785,507,000			$ 1,785,507,000		1,569,549,000	$ 1,785,507,000
Public Service Company of New Mexico [Member] | Reeves station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Requirements to be implemented | requirement				0			0			0
Public Service Company of New Mexico [Member] | San Juan Generating Station Units 2 and 3 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Plant in service, held for future use, and to be abandoned				$ 471,600,000			$ 471,600,000			$ 471,600,000
Accumulated depreciation and amortization				201,400,000			201,400,000			201,400,000
Net book value				270,200,000			270,200,000			270,200,000
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Loss on long-term purchase commitment [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs									$ 16,500,000
Estimate of possible loss				$ 103,000,000			$ 103,000,000			$ 103,000,000
Public Service Company of New Mexico [Member] | San Juan Generating Station And Four Corners [Member] | Maximum [Member]
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						75		75					70
Public Service Company of New Mexico [Member] | San Juan Generating Station And Four Corners [Member] | Minimum [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Proposed government standard emission limit (in ozone parts per million) | parts_per_billion																		60
PNMR and PNM [Member] | Palo Verde Nuclear Generating Station Unit 3 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Number of megawatts | MW				134			134			134
Clean Air Act related to Regional Haze [Member]
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 [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Number of other joint owners | joint_owner				8			8			8
Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated costs to remain unrecovered		$ 20,000,000
Expense reflected in regulatory disallowances and restructuring costs				$ 5,200,000
Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Units 1 and 4 [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Total costs for equipment										$ 76,800,000
Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Units 2 and 3 [Member]
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							20 years
Recovery percentage of estimated undepreciated value at 12/31/17		50.00%		50.00%			50.00%		50.00%	50.00%
Estimated undepreciated value at 12/31/17									$ 255,300,000
Regulatory disallowances and restructuring costs									127,600,000
Expense reflected in regulatory disallowances and restructuring costs				$ 400,000	$ 800,000
Accumulated plant write-off, disallowance				128,600,000			$ 128,600,000			$ 128,600,000
Net carrying value of utility plant				$ 141,600,000			141,600,000			141,600,000
Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Units 2 and 3 [Member] | Increase in coal mine decommissioning liability [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs									$ 165,700,000
Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]
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
Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member] | Maximum [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Annual cost of Renewable Energy Credits		$ 7,000,000
Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station Unit 3 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated undepreciated value at 12/31/17		$ 152,000,000
Clean Air Act, SNCR [Member] | PNMR and PNM [Member] | Palo Verde Nuclear Generating Station Unit 3 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Number of megawatts | MW		134
Clean Air Act, SNCR [Member] | PNMR Development [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Expense for cost, obligation to reimburse					$ 600,000
Potential acquisition of ownership (in megawatts) | MW														65
Clean Air Act, SNCR Hearing Examiner Recommended Denial [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]
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 [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]
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 [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Expense reflected in regulatory disallowances and restructuring costs				$ 4,800,000
Clean Air Act Related to Post Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners [Member]
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
Plant requirement to meet opacity limit															20.00%
Rule imposes opacity limitation on certain fugitive dust emissions from coal and material handling operations															20.00%
Estimate of possible loss				$ 90,100,000			$ 90,100,000			$ 90,100,000
Clean Air Act Related to Post Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners Units 4 and 5 (Coal) [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Ownership percentage															13.00%
Clean Air Act Related to Post Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners Units 1, 2 and 3 (Coal) [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Ownership percentage															0.00%
Clean Power Plan [Member]
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
Proposed percentage reduction in CO2 emissions, stayed by the USSC											32.00%
Period of time currently remaining to submit initial plans to meet environmental targets							6 months
Period of time currently remaining to submit initial plans to meet environmental targets, including potential extension							2 years 6 months
National Ambient Air Quality Standards, 2015 EPA Legal Settlement [Member] | Public Service Company of New Mexico [Member]
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 [Member] | Public Service Company of New Mexico [Member] | Minimum [Member]
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, 2015 EPA Legal Settlement [Member] [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Period of time from state designation, to provide implementation plans	36 months
WEG v OSM Lawsuit [Member] | Public Service Company of New Mexico [Member]
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 [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Number of claims for relief, filed (in lawsuits) | lawsuit																2
Santa Fe generating station [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Number of wells with elevated levels of nitrates | well				3			3			3

XML

Commitments and Contingencies - Coal Supply (Details)			3 Months Ended		9 Months Ended		12 Months Ended
	Feb. 01, 2016 USD ($)	Jan. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)	Nov. 01, 2016 USD ($)	Oct. 21, 2016 USD ($)	Aug. 31, 2016 USD ($)	Aug. 30, 2016 USD ($)	Aug. 01, 2016 USD ($) payment	Jul. 19, 2016 USD ($)	Apr. 30, 2016 USD ($)
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets			$ 89,746,000		$ 89,746,000		$ 82,104,000
Regulatory disallowances and restructuring costs			16,451,000	$ 0	17,225,000	$ 1,744,000
Mine reclamation trust requirement funded			1,900,000
San Juan Generating Station [Member] | Coal Supply [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Replacement Coal Mine Reclamation Bonds posted by alternate surety companies													$ 118,700,000
Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets			81,419,000		81,419,000		74,990,000
Regulatory disallowances and restructuring costs			16,451,000	$ 0	17,225,000	$ 1,744,000
Public Service Company of New Mexico [Member] | Increase in coal mine decommissioning liability [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Expense reflected in regulatory disallowances and restructuring costs			4,800,000
Public Service Company of New Mexico [Member] | Mine Reclamation Trust [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Required contribution to Reclamation Trust, current fiscal year			3,500,000		3,500,000
Anticipated funding to Reclamation Trust, next fiscal year			4,700,000		4,700,000
Anticipated funding to Reclamation Trust, third fiscal year			5,100,000		5,100,000
Public Service Company of New Mexico [Member] | Mine Reclamation Trust [Member] | Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Anticipated funding to Reclamation Trust, next fiscal year			2,000,000		2,000,000
Anticipated funding to Reclamation Trust, third fiscal year			2,000,000		2,000,000
Number of annual installment payments | payment												13
Public Service Company of New Mexico [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory assets			100,000,000		100,000,000
Public Service Company of New Mexico [Member] | Loss on long-term purchase commitment [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual			41,400,000		41,400,000		38,800,000
Final reclamation, capped amount to be collected					100,000,000.0
Public Service Company of New Mexico [Member] | Loss on long-term purchase commitment [Member] | Underground [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual			13,900,000		13,900,000		11,400,000
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Loss on long-term purchase commitment [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowances and restructuring costs							16,500,000
Estimate of possible loss			103,000,000		103,000,000
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Loss on long-term purchase commitment [Member] | Underground [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss			129,400,000		129,400,000
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Coal Supply [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets			$ 54,100,000		$ 54,100,000		49,000,000
Estimated increase in coal cost			40.00%		40.00%
NM Capital [Member] | BTMU Term Loan Agreement [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Term loans	$ 125,000,000.0		$ 107,800,000.0		$ 107,800,000.0
NM Capital [Member] | BTMU Term Loan Agreement [Member] | Maximum [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Debt-to-capital ratio covenant	65.00%
NM Capital [Member] | San Juan Generating Station [Member] | Coal Supply [Member]
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
Initial interest rate		7.25%
Requirement to post reclamation bonds							161,600,000							$ 118,700,000
Cash used to support bank letter or credit arrangement							$ 40,000,000						$ 30,300,000
NM Capital [Member] | San Juan Coal Company, Westmoreland [Member] | Coal Supply [Member]
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	110,000,000		110,000,000
Scheduled principal payment proceeds												$ 15,000,000
Prepayment penalty			$ 0		$ 0
Cash used to support bank letter or credit arrangement										$ 30,300,000	$ 40,000,000
NM Capital [Member] | San Juan Coal Company, Westmoreland [Member] | Coal Supply [Member] | Subsequent event [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Scheduled principal payment proceeds								$ 15,000,000
Scheduled interest payment proceeds								$ 2,300,000
Unaffiliated third party [Member] | San Juan Coal Company, Westmoreland [Member] | Coal Supply [Member] | Subsequent event [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Amount held in a restricted bank account									$ 17,300,000

XML

Commitments and Contingencies - Royalty Rates, Tax Assessment, Insurance and Other Matters (Details)	Sep. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 01, 2015 Allotment_Parcel	Jul. 13, 2015 a	Jan. 22, 2015 Allotment_Parcel	Apr. 02, 2014 landowner Allotment_Parcel	Jan. 06, 2014 Allotment_Parcel	Aug. 31, 2013	May 23, 2013 USD ($)	Sep. 30, 2012 landowner
Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member] | Nuclear Plant [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Ownership percentage in nuclear reactor	10.20%
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 [Member] | Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Commercial Providers [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage	375,000,000
Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Industry Wide Retrospective Assessment Program [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage	13,100,000,000.0
Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Maximum [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage	13,500,000,000.0
Liability insurance coverage sublimit	$ 2,250,000,000.00
Continuous Highwall Mining [Member] | San Juan Generating Station [Member]
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%
NMTRD Coal Severance Tax [Member] | Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Assessed coal severance surtax, penalty and interest									$ 30,000,000
Share of settlement in addition to amounts previously paid		$ 100,000
Navajo Nation Allottee Matters [Member] | Public Service Company of New Mexico [Member]
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

XML

Regulatory and Rate Matters - PNM (Details)												3 Months Ended		9 Months Ended		12 Months Ended	43 Months Ended
	Sep. 30, 2016 USD ($) MW	Sep. 29, 2016 USD ($)	Sep. 28, 2016 USD ($) MW	Aug. 04, 2016 USD ($) MW	Apr. 15, 2016 USD ($) GWh	Feb. 03, 2016	Jan. 21, 2016 MW	Jan. 15, 2016 lease MW	Aug. 27, 2015 USD ($)	Mar. 20, 2015 USD ($) party	Jan. 15, 2015	Sep. 30, 2016 USD ($) MW	Sep. 30, 2015 USD ($) MW	Sep. 30, 2016 USD ($) MW	Sep. 30, 2015 USD ($) MW	Dec. 31, 2015	Sep. 30, 2016 USD ($) MW	Jul. 08, 2016 MW	Apr. 26, 2016 turbine MW	Feb. 26, 2016 USD ($)	Jan. 31, 2016 MW	Dec. 31, 2013	Mar. 01, 2013	Dec. 31, 2012 USD ($)
Public Utilities, General Disclosures [Line Items]
Excess return on jurisdictional equity that would require refund	0.50%											0.50%		0.50%			0.50%
Public Service Company of New Mexico [Member]
Public Utilities, General Disclosures [Line Items]
Duration of resource portfolio														20 years
Public Service Company of New Mexico [Member] | San Juan Generating Station Units 1 and 4 [Member] | Clean Air Act, Balanced Draft Technology [Member]
Public Utilities, General Disclosures [Line Items]
Net book value	$ 49,900,000											$ 49,900,000		$ 49,900,000			$ 49,900,000
Public Service Company of New Mexico [Member] | San Juan Generating Station Units 1 and 4 [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Clean Air Act, Balanced Draft Technology [Member]
Public Utilities, General Disclosures [Line Items]
Installation costs																	52,300,000
Public Service Company of New Mexico [Member] | San Juan Generating Station Units 1 and 4 [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Clean Air Act, SNCR [Member]
Public Utilities, General Disclosures [Line Items]
Installation costs																	76,800,000
Public Service Company of New Mexico [Member] | San Juan Generating Station Units 2 and 3 [Member]
Public Utilities, General Disclosures [Line Items]
Net book value	270,200,000											270,200,000		270,200,000			270,200,000
Public Service Company of New Mexico [Member] | San Juan Generating Station Units 2 and 3 [Member] | Clean Air Act, SNCR [Member]
Public Utilities, General Disclosures [Line Items]
Newly identified replacement gas-fired generation (in megawatts) | MW													187		187				80
Number of aeroderivative units (in turbines) | turbine																			2
Replacement gas-fired aeroderivative generation (in megawatts) | MW																			40
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases [Member]
Public Utilities, General Disclosures [Line Items]
Number of megawatts purchased (in megawatts) | MW								64.1													64.1
Number of leases under which assets were purchased | lease								3
Estimated annual property tax expense	$ 800,000											$ 800,000		$ 800,000			$ 800,000
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								114.6		114.6			114.6
Net book value	$ 76,900,000											$ 76,900,000		$ 76,900,000			$ 76,900,000
Net book value of capitalized improvements	41,700,000											41,700,000		41,700,000			41,700,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 1 Leases, extended [Member]
Public Utilities, General Disclosures [Line Items]
Estimated annual property tax expense	1,500,000											1,500,000		1,500,000			1,500,000
Estimated annual rent expense	$ 18,100,000											18,100,000		18,100,000			$ 18,100,000
Number of leases under which lease term was extended | lease								4
Lease term extension period											8 years
Public Service Company of New Mexico [Member] | 2015 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease)									$ 123,500,000
Requested rate increase (decrease) of non-fuel revenue									$ 121,700,000					121,500,000
Requested return on equity									10.50%
Requested rate increase (decrease) for fuel related costs														(42,900,000)
Requested rate increase (decrease) for non-fuel related revenues														$ (200,000)
Hearing examiner's recommended rate increase (decrease) of non-fuel revenue				$ 41,300,000
Hearing examiner's recommended return on equity				9.575%
Approved rate increase (decrease)			$ 61,200,000
Estimated period of time for supreme court appeal decision	15 months
Approved recovery of net operating loss carryforward												2,100,000
Public Service Company of New Mexico [Member] | 2015 Electric Rate Case [Member] | San Juan Generating Station Units 1 and 4 [Member] | Clean Air Act, Balanced Draft Technology [Member]
Public Utilities, General Disclosures [Line Items]
Requested base rate increase (decrease)									$ 40,000,000
Public Service Company of New Mexico [Member] | 2015 Electric Rate Case [Member] | San Juan Generating Station [Member] | Refined Coal [Member]
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 [Member] | 2015 Electric Rate Case [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases [Member]
Public Utilities, General Disclosures [Line Items]
Hearing examiner's proposed disallowance of recovery				$ 163,300,000
Initial rate base value			83,700,000
Disallowance of the recovery underpreciated costs of capitalized leasehold improvements			43,800,000
Pre-tax regulatory disallowance												$ 6,800,000
Period of time for which capital improvements were disallowed	15 months
Public Service Company of New Mexico [Member] | 2015 Electric Rate Case [Member] | Palo Verde Nuclear Generating Station, Unit 1 Leases, extended [Member]
Public Utilities, General Disclosures [Line Items]
Hearing examiner's recommended rent expense recovery amount				0
Hearing examiner's recommended recovery amount on conversions				0
Recovery of assumed operating and maintenance expense savings annually			$ 300,000
Public Service Company of New Mexico [Member] | 2015 Electric Rate Case [Member] | Palo Verde Nuclear Generating Station, Units 1 and 2 Leases [Member]
Public Utilities, General Disclosures [Line Items]
Hearing examiner's recommended property tax recovery amount				0
Public Service Company of New Mexico [Member] | 2015 Electric Rate Case [Member] | Alvarado square [Member]
Public Utilities, General Disclosures [Line Items]
Hearing examiner's recommended amount to not be recovered from retail customers				4,500,000
Pre-tax regulatory disallowance of costs recorded as regulatory assets and deferred charges				$ 4,500,000
Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Profit incentive sliding scale multiplier		7.10%
Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Reasonable cost threshold	3.00%											3.00%		3.00%			3.00%					3.00%
Profit incentive sliding scale multiplier		9.00%
Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Wind Energy [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Required percentage of diversification	30.00%											30.00%		30.00%			30.00%
Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Solar Energy [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Required percentage of diversification	20.00%											20.00%		20.00%			20.00%
Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Distributed Generation [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Required percentage of diversification	3.00%											3.00%		3.00%			3.00%
Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Renewable Technologies [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Required percentage of diversification	5.00%											5.00%		5.00%			5.00%
Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Required Percentage by 2011 [Member]
Public Utilities, General Disclosures [Line Items]
Required percentage of renewable energy in portfolio to electric sales	10.00%											10.00%		10.00%			10.00%
Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Required Percentage by 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Required percentage of renewable energy in portfolio to electric sales	15.00%											15.00%		15.00%			15.00%
Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Required Percentage by 2020 [Member]
Public Utilities, General Disclosures [Line Items]
Required percentage of renewable energy in portfolio to electric sales	20.00%											20.00%		20.00%			20.00%
Public Service Company of New Mexico [Member] | Renewable Energy Rider [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Proposal to collect funds under renewable energy procurement plan	$ 42,400,000											$ 42,400,000		$ 42,400,000			$ 42,400,000
Annual revenue to be collected under rider rate	$ 50,000,000											50,000,000		$ 50,000,000			$ 50,000,000
Approved return on equity						10.00%										10.50%
Public Service Company of New Mexico [Member] | 2017 Energy Efficiency and Load Management Program [Member] | Disincentives / Incentives Adder [Member]
Public Utilities, General Disclosures [Line Items]
Program portfolio's total budget		$ 26,000,000			$ 28,000,000
Incentive based on target savings					$ 2,400,000
Targeted savings (in gigawatt hours) | GWh					75
Public Service Company of New Mexico [Member] | Integrated Resource Plan, 2011 [Member]
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 [Member] | Advanced Metering Infrastructure Costs [Member]
Public Utilities, General Disclosures [Line Items]
Estimated costs to be recovered																				$ 87,200,000
Estimated future investment																				$ 33,000,000
Public Service Company of New Mexico [Member] | Formula Transmission Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease)										$ 1,300,000
Amount of regulatory costs not yet approved																								$ 3,200,000
Return on equity										10.00%														10.81%
Percentage ownership of EIP transmission line																							60.00%
Number of other parties entered into settlement agreement | party										5
Public Service Company of New Mexico [Member] | Firm Requirements Wholesale Power Rate Case, Navopache [Member] [Member]
Public Utilities, General Disclosures [Line Items]
Number of megawatts served under a short-term coordination tariff | MW							10
Revenue for power sold under PSA												$ 4,800,000	$ 6,300,000	$ 14,800,000	$ 19,700,000
PNMR Development [Member]
Public Utilities, General Disclosures [Line Items]
Solar generation capacity (in megawatts) | MW																		30
Construction of solar generation capacity (in megawatts) | MW	10											10		10			10

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Regulatory and Rate Matters - TNMP Narrative (Details) - Texas-New Mexico Power Company [Member]			1 Months Ended	9 Months Ended
	Jul. 27, 2016 USD ($)	May 27, 2016 USD ($)	Jul. 30, 2011 USD ($)	Sep. 30, 2016 USD ($) advanced_meter	Oct. 21, 2016 customer	Oct. 02, 2015 USD ($)	Aug. 15, 2013 USD ($) customer
Advanced Meter System Deployment and Surcharge Request [Member]
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				242,246
Completion period of advanced meter deployment			5 years
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
Cost and savings reconciliation filed with regulators, capital cost savings						$ 71,000,000
Cost and savings reconciliation filed with regulators, operations and maintenance savings						$ 18,000,000
Program costs incurred to date				$ 1,500,000
Advanced Meter System Deployment and Surcharge Request [Member] | Subsequent event [Member]
Public Utilities, General Disclosures [Line Items]
Current number of customers that have elected non-standard meter service (in customers) | customer					100
Advanced Meter System Deployment and Surcharge Request [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Approved non-standard metering service cost, initial fee range							$ 63.97
Advanced Meter System Deployment and Surcharge Request [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Approved non-standard metering service cost, initial fee range							$ 168.61
Energy Efficiency [Member]
Public Utilities, General Disclosures [Line Items]
Requested adjustment to EECRF		$ 6,100,000
Requested adjustment to EECRF, performance bonus		$ 800,000
Approved program cost recovery	$ 6,000,000
Approved performance bonus	$ 800,000

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Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - Texas-New Mexico Power Company [Member] - Transmission Cost of Service Rates [Member] - USD ($) $ in Millions	6 Months Ended
	Mar. 15, 2017	Sep. 09, 2016	Mar. 22, 2016	Sep. 09, 2015	Mar. 15, 2015
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base		$ 25.8	$ 7.0	$ 27.1	$ 25.2
Annual Increase in Revenue		$ 4.3	$ 1.4	$ 4.4	$ 4.2
Subsequent event [Member]
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base	$ 9.5
Annual Increase in Revenue	$ 1.8

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Income Taxes (Details) - USD ($)	3 Months Ended			9 Months Ended	12 Months Ended
	Sep. 30, 2016	Mar. 31, 2016	Mar. 31, 2015	Sep. 30, 2016	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2012
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		$ (7,100,000)	$ (2,000,000)
Impairment of state net operating loss carryforward			1,000,000	$ 0
Interest income and interest expense applicable to federal income tax matters [Member]
Income Tax Contingency [Line Items]
Net refunds from the IRS	$ 6,500,000
Increase (decrease) of interest receivable	(2,100,000)
Interest income	5,100,000
Interest expense	700,000
Consulting expense fees	900,000
Net settlement with taxing authority, pre-tax	3,500,000
Corporate and Other [Member]
Income Tax Contingency [Line Items]
Increase (decrease) in tax expense due to tax rate change		(100,000)	(200,000)
Impairment of state net operating loss carryforward			300,000
Corporate and Other [Member] | Interest income and interest expense applicable to federal income tax matters [Member]
Income Tax Contingency [Line Items]
Net settlement with taxing authority, pre-tax, segment allocation	600,000
Public Service Company of New Mexico [Member] | Interest income and interest expense applicable to federal income tax matters [Member]
Income Tax Contingency [Line Items]
Net settlement with taxing authority, pre-tax, segment allocation	2,600,000
Texas-New Mexico Power Company [Member] | Interest income and interest expense applicable to federal income tax matters [Member]
Income Tax Contingency [Line Items]
Net settlement with taxing authority, pre-tax, segment allocation	300,000
Public Service Company of New Mexico [Member]
Income Tax Contingency [Line Items]
Increase (decrease) in deferred tax assets as a result of tax rate changes		(700,000)	700,000
Increase (decrease) in tax expense due to tax rate change		$ 800,000	(500,000)
Impairment of state net operating loss carryforward			$ 700,000
Public Service Company of New Mexico [Member] | 2015 Electric Rate Case [Member]
Income Tax Contingency [Line Items]
Approved recovery of net operating loss carryforward	$ 2,100,000
Texas-New Mexico Power Company [Member]
Income Tax Contingency [Line Items]
Impairment of state net operating loss carryforward					$ 0

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Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Service billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 22,189	$ 21,894	$ 67,192	$ 65,961
Service billings [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	6,593	6,707	20,881	20,366
Service billings [Member] | PNM to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	105	136	347	424
Service billings [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	10	0	30	0
Interest billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	3	10	8	38
Interest billings [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	13	34	112	167
Interest billings [Member] | PNM to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	38	24	110	79
Income tax sharing payments [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	0	1,450
Income tax sharing payments [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 0	$ 0	$ 0	$ 0

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Goodwill (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Apr. 01, 2016	Dec. 31, 2015	Sep. 30, 2015	Apr. 01, 2015
Goodwill [Line Items]
Goodwill	$ 278,297		$ 278,297	$ 278,297
Public Service Company of New Mexico [Member]
Goodwill [Line Items]
Goodwill	51,632	$ 51,600	51,632		$ 51,600
Carrying value exceeded		25.00%			25.00%
Texas-New Mexico Power Company [Member]
Goodwill [Line Items]
Goodwill	$ 226,665	$ 226,700	$ 226,665
Carrying value exceeded		32.00%