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, 2013

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 25, 2013, 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 25, 2013 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 25, 2013 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	7
Condensed Consolidated Statements of Comprehensive Income	8
Condensed Consolidated Statements of Cash Flows	9
Condensed Consolidated Balance Sheets	11
Condensed Consolidated Statement of Changes in Equity	13
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	14
Condensed Consolidated Statements of Comprehensive Income	15
Condensed Consolidated Statements of Cash Flows	16
Condensed Consolidated Balance Sheets	18
Condensed Consolidated Statement of Changes in Equity	20
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	21
Condensed Consolidated Statements of Comprehensive Income	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	71
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	94
ITEM 4. CONTROLS AND PROCEDURES	97
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	98
ITEM 1A. RISK FACTORS	98
ITEM 6. EXHIBITS	99
SIGNATURE	100

3

GLOSSARY

Definitions:
Afton	Afton Generating Station
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
AMS	Advanced Meter System
AOCI	Accumulated Other Comprehensive Income
APS	Arizona Public Service Company, which is the operator and a co-owner of PVNGS and Four Corners
BACT	Best Available Control Technology
BART	Best Available Retrofit Technology
BHP	BHP Billiton, Ltd, the parent of SJCC
Board	Board of Directors of PNMR
BTU	British Thermal Unit
CAA	Clean Air Act
CCB	Coal Combustion Byproducts
CCN	Certificate of Convenience and Necessity
CO2	Carbon Dioxide
CTC	Competition Transition Charge
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
Delta	Delta-Person Generating Station
DOE	United States Department of Energy
DOI	United States Department of Interior
EIB	New Mexico Environmental Improvement Board
EIP	Eastern Interconnection Project
EPA	United States Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
ESA	Endangered Species Act
Exchange Act	Securities Exchange Act of 1934
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIP	Federal Implementation Plan
First Choice	FCP Enterprises, Inc. and Subsidiaries
Four Corners	Four Corners Power Plant
FPPAC	Fuel and Purchased Power Adjustment Clause
GAAP	Generally Accepted Accounting Principles in the United States of America
Gallup	City of Gallup, New Mexico
GHG	Greenhouse Gas Emissions
GWh	Gigawatt hours
IBEW	International Brotherhood of Electrical Workers
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
KW	Kilowatt
KWh	Kilowatt Hour
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.

4

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.
NERC	North American Electric Reliability Council
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NMAG	New Mexico Attorney General
NMED	New Mexico Environment Department
NMIEC	New Mexico Industrial Energy Consumers Inc.
NMPRC	New Mexico Public Regulation Commission
NOx	Nitrogen Oxides
NOI	Notice of Inquiry
NOPR	Notice of Proposed Rulemaking
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
PNM	Public Service Company of New Mexico and Subsidiaries
PNM Revolving Credit Facility	PNM's $400.0 Million Unsecured Revolving Credit Facility
PNM Term Loan Agreement	PNM's $75.0 Million Unsecured Term Loan Facility
PNMR	PNM Resources, Inc. and Subsidiaries
PNMR Revolving Credit Facility	PNMR's $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan Agreement	PNMR's $100.0 Million Unsecured Term Loan Facility
PPA	Power Purchase Agreement
PSD	Prevention of Significant Deterioration
PUCT	Public Utility Commission of Texas
PV	Photovoltaic
PVNGS	Palo Verde Nuclear Generating Station
RCRA	Resource Conservation and Recovery Act
RCT	Reasonable Cost Threshold
REA	New Mexico's Renewable Energy Act of 2004
REC	Renewable Energy Certificates
REP	Retail Electricity Provider
RMC	Risk Management Committee
RPS	Renewable Energy Portfolio Standard
SCE	Southern California Edison Company
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

5

SO2	Sulfur Dioxide
SPS	Southwestern Public Service Company
S&P	Standard and Poor's Ratings Services
TECA	Texas Electric Choice Act
Tenth Circuit	United States Court of Appeals for the Tenth Circuit
TNMP	Texas-New Mexico Power Company and Subsidiaries
TNMP Revolving Credit Facility	TNMP's $75.0 Million Revolving Credit Facility
TNP	TNP Enterprises, Inc. and Subsidiaries
Tri-State	Tri-State Generation and Transmission Association, Inc.
Valencia	Valencia Energy Facility
VaR	Value at Risk
WEG	WildEarth Guardians

6

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,
	2013			2012			2013			2012
	(In thousands, except per share amounts)
Electric Operating Revenues	$	399,730		$	390,411		$	1,064,993		$	1,019,646
Operating Expenses:
Cost of energy	114,674			110,777			325,039			297,342
Administrative and general	46,915			45,283			134,744			135,371
Energy production costs	41,142			40,365			131,546			131,546
Regulatory disallowances	1,735			—			1,735			—
Depreciation and amortization	42,743			42,820			125,189			122,289
Transmission and distribution costs	17,248			17,082			50,690			50,896
Taxes other than income taxes	17,534			15,934			49,739			45,218
Total operating expenses	281,991			272,261			818,682			782,662
Operating income	117,739			118,150			246,311			236,984
Other Income and Deductions:
Interest income	2,264			3,130			7,731			9,808
Gains on investments held by NDT	2,190			5,716			6,995			9,376
Other income	3,252			2,484			7,517			6,991
Other (deductions)	(5,970		)	(3,451		)	(13,516		)	(10,719		)
Net other income (deductions)	1,736			7,879			8,727			15,456
Interest Charges	30,365			30,515			92,279			90,280
Earnings before Income Taxes	89,110			95,514			162,759			162,160
Income Taxes	30,296			33,538			58,600			54,609
Net Earnings	58,814			61,976			104,159			107,551
(Earnings) Attributable to Valencia Non-controlling Interest	(4,127		)	(3,980		)	(10,904		)	(10,699		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Net Earnings Attributable to PNMR	$	54,555		$	57,864		$	92,859		$	96,456
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.68		$	0.73		$	1.16		$	1.21
Diluted	$	0.68		$	0.72		$	1.15		$	1.20
Dividends Declared per Common Share	$	0.165		$	0.145		$	0.495		$	0.435

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

7

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Net Earnings	$	58,814		$	61,976		$	104,159		$	107,551
Other Comprehensive Income:
Unrealized Gain on Investment Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(4,143), $(4,972), $(7,544) and $(15,409)	6,322			7,587			11,512			23,511
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $925, $4,248, $3,639 and $12,786	(1,411		)	(6,481		)	(5,551		)	(19,509		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(631), $(476), $(1,893) and $(1,428)	960			727			2,880			2,181
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $128, $51, $127 and $150	(238		)	(92		)	(236		)	(270		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(19), $(16), $(54) and $(47)	35			29			99			85
Total Other Comprehensive Income	5,668			1,770			8,704			5,998
Comprehensive Income	64,482			63,746			112,863			113,549
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,127		)	(3,980		)	(10,904		)	(10,699		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Comprehensive Income Attributable to PNMR	$	60,223		$	59,634		$	101,563		$	102,454

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 CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2013			2012
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	104,159		$	107,551
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	157,856			153,992
Deferred income tax expense	57,878			55,141
Net unrealized (gains) losses on commodity derivatives	(5,858		)	3,076
Realized (gains) on investments held by NDT	(6,995		)	(9,376		)
Stock based compensation expense	4,315			2,748
Regulatory disallowances	1,735			—
Other, net	1,444			(2,037		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(23,731		)	(31,550		)
Materials, supplies, and fuel stock	(724		)	(6,769		)
Other current assets	(6,667		)	(4,225		)
Other assets	21,656			(9,499		)
Accounts payable	(17,786		)	3,973
Accrued interest and taxes	126,218			22,336
Other current liabilities	(32,111		)	(21,681		)
Proceeds from governmental grants	—			21,567
Other liabilities	(70,379		)	(80,248		)
Net cash flows from operating activities	311,010			204,999
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(233,928		)	(214,743		)
Proceeds from sales of investments held by NDT	179,336			136,305
Purchases of investments held by NDT	(181,401		)	(138,658		)
Proceeds from sale of First Choice	—			4,034
Return of principal on PVNGS lessor notes	23,357			23,455
Other, net	1,210			1,627
Net cash flows from investing activities	(211,426		)	(187,980		)

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,
	2013			2012
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(46,700		)	30,700
Long-term borrowings	75,000			20,000
Repayment of long-term debt	(26,037		)	(20,000		)
Cash paid in debt exchange	(13,048		)	—
Proceeds from stock option exercise	3,500			10,301
Awards of common stock	(12,429		)	(21,930		)
Dividends paid	(38,233		)	(33,454		)
Valencia's transactions with its owner	(13,477		)	(12,034		)
Other, net	(3,706		)	(337		)
Net cash flows from financing activities	(75,130		)	(26,754		)
Change in Cash and Cash Equivalents	24,454			(9,735		)
Cash and Cash Equivalents at Beginning of Period	8,985			15,091
Cash and Cash Equivalents at End of Period	$	33,439		$	5,356
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	71,824		$	64,040
Income taxes paid (refunded), net	$	(95,472	)	$	5,302
Supplemental schedule of noncash financing activities:
Premium on long-term debt incurred in connection with debt exchange	$	23,249

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

10

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2013		December 31, 2012
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	33,439	$	8,985
Accounts receivable, net of allowance for uncollectible accounts of $1,391 and $1,751	110,937		87,093
Unbilled revenues	55,155		57,266
Other receivables	53,681		53,332
Materials, supplies, and fuel stock	60,367		59,643
Regulatory assets	38,511		39,120
Commodity derivative instruments	5,743		3,785
Income taxes receivable	5,283		101,477
Other current assets	37,404		31,490
Total current assets	400,520		442,191
Other Property and Investments:
Investment in PVNGS lessor notes	32,542		54,325
Investments held by NDT	207,483		188,971
Other investments	6,725		9,139
Non-utility property, net of accumulated depreciation of $143 and $131	4,475		4,487
Total other property and investments	251,225		256,922
Utility Plant:
Plant in service and plant held for future use	5,431,680		5,313,796
Less accumulated depreciation and amortization	1,839,481		1,774,223
	3,592,199		3,539,573
Construction work in progress	175,410		125,287
Nuclear fuel, net of accumulated amortization of $52,876 and $42,644	79,458		81,627
Net utility plant	3,847,067		3,746,487
Deferred Charges and Other Assets:
Regulatory assets	551,607		555,577
Goodwill	278,297		278,297
Commodity derivative instruments	4,284		352
Other deferred charges	95,814		92,757
Total deferred charges and other assets	930,002		926,983
	$	5,428,814	$	5,372,583

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, 2013			December 31, 2012
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Short-term debt	$	112,000		$	158,700
Current installments of long-term debt	52,530			2,530
Accounts payable	76,309			99,177
Customer deposits	14,171			18,176
Accrued interest and taxes	82,801			52,003
Regulatory liabilities	1,218			15,173
Commodity derivative instruments	1,017			1,000
Dividends declared	13,271			11,679
Current portion of accumulated deferred income taxes	258			258
Other current liabilities	62,018			75,407
Total current liabilities	415,593			434,103
Long-term Debt	1,696,311			1,669,760
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	743,828			701,545
Accumulated deferred investment tax credits	12,598			14,242
Regulatory liabilities	456,634			423,460
Asset retirement obligations	93,519			85,893
Accrued pension liability and postretirement benefit cost	147,442			224,565
Commodity derivative instruments	1,347			1,933
Other deferred credits	106,554			116,523
Total deferred credits and other liabilities	1,561,922			1,568,161
Total liabilities	3,673,826			3,672,024
Commitments and Contingencies (See Note 10)
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 outstanding (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,177,686			1,182,819
Accumulated other comprehensive income (loss), net of income taxes	(72,926		)	(81,630		)
Retained earnings	560,429			506,998
Total PNMR common stockholders' equity	1,665,189			1,608,187
Non-controlling interest in Valencia	78,270			80,843
Total equity	1,743,459			1,689,030
	$	5,428,814		$	5,372,583

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

12

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 Stockholder's Equity						Total Equity
	(In thousands)
Balance at December 31, 2012	$	1,182,819		$	(81,630	)	$	506,998		$	1,608,187		$	80,843		$	1,689,030
Proceeds from stock option exercise	3,500			—			—			3,500			—			3,500
Awards of common stock	(12,429		)	—			—			(12,429		)	—			(12,429		)
Excess tax (shortfall) from stock-based payment arrangements	(519		)	—			—			(519		)	—			(519		)
Stock based compensation expense	4,315			—			—			4,315			—			4,315
Valencia's transactions with its owner	—			—			—			—			(13,477		)	(13,477		)
Net earnings before subsidiary preferred stock dividends	—			—			93,255			93,255			10,904			104,159
Subsidiary preferred stock dividends	—			—			(396		)	(396		)	—			(396		)
Total other comprehensive income	—			8,704			—			8,704			—			8,704
Dividends declared on common stock	—			—			(39,428		)	(39,428		)	—			(39,428		)
Balance at September 30, 2013	$	1,177,686		$	(72,926	)	$	560,429		$	1,665,189		$	78,270		$	1,743,459

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

13

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,
	2013			2012			2013			2012
	(In thousands)
Electric Operating Revenues	$	326,026		$	321,731		$	863,609		$	832,242
Operating Expenses:
Cost of energy	100,200			99,217			283,715			263,009
Administrative and general	40,679			41,150			116,058			120,857
Energy production costs	41,142			40,365			131,546			131,546
Regulatory disallowances	1,735			—			1,735			—
Depreciation and amortization	25,879			24,437			77,763			72,017
Transmission and distribution costs	11,686			11,172			33,420			33,679
Taxes other than income taxes	9,488			8,417			28,613			25,386
Total operating expenses	230,809			224,758			672,850			646,494
Operating income	95,217			96,973			190,759			185,748
Other Income and Deductions:
Interest income	2,298			3,173			7,839			9,938
Gains on investments held by NDT	2,190			5,716			6,995			9,376
Other income	2,396			1,176			5,269			4,378
Other (deductions)	(2,375		)	(1,682		)	(5,287		)	(4,553		)
Net other income (deductions)	4,509			8,383			14,816			19,139
Interest Charges	20,124			19,230			59,971			56,652
Earnings before Income Taxes	79,602			86,126			145,604			148,235
Income Taxes	27,652			31,235			49,184			51,929
Net Earnings	51,950			54,891			96,420			96,306
(Earnings) Attributable to Valencia Non-controlling Interest	(4,127		)	(3,980		)	(10,904		)	(10,699		)
Net Earnings Attributable to PNM	47,823			50,911			85,516			85,607
Preferred Stock Dividends Requirements	(132		)	(132		)	(396		)	(396		)
Net Earnings Available for PNM Common Stock	$	47,691		$	50,779		$	85,120		$	85,211

The accompanying notes, as they relate to PNM, 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 COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Net Earnings	$	51,950		$	54,891		$	96,420		$	96,306
Other Comprehensive Income:
Unrealized Gain on Investment Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(4,143), $(4,972), $(7,544) and $(15,409)	6,322			7,587			11,512			23,511
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $925, $4,248, $3,639 and $12,786	(1,411		)	(6,481		)	(5,551		)	(19,509		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(631), $(476), $(1,893) and $(1,428)	960			727			2,880			2,181
Total Other Comprehensive Income	5,871			1,833			8,841			6,183
Comprehensive Income	57,821			56,724			105,261			102,489
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,127		)	(3,980		)	(10,904		)	(10,699		)
Comprehensive Income Attributable to PNM	$	53,694		$	52,744		$	94,357		$	91,790

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 CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2013			2012
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	96,420		$	96,306
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	104,161			97,086
Deferred income tax expense	49,870			52,558
Net unrealized (gains) losses on commodity derivatives	(5,858		)	3,076
Realized (gains) on investments held by NDT	(6,995		)	(9,376		)
Regulatory disallowances	1,735			—
Other, net	(1,282		)	(1,005		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(14,123		)	(26,183		)
Materials, supplies, and fuel stock	(744		)	(6,404		)
Other current assets	(5,187		)	(6,942		)
Other assets	21,977			(9,425		)
Accounts payable	(4,953		)	2,353
Accrued interest and taxes	66,090			80,418
Other current liabilities	(43,935		)	(9,850		)
Proceeds from governmental grants	—			21,567
Other liabilities	(67,062		)	(75,629		)
Net cash flows from operating activities	190,114			208,550
Cash Flows From Investing Activities:
Utility plant additions	(164,669		)	(144,571		)
Proceeds from sales of NDT investments	179,336			136,305
Purchases of NDT investments	(181,401		)	(138,658		)
Return of principal on PVNGS lessor notes	23,357			23,455
Other, net	1,212			(720		)
Net cash flows from investing activities	(142,165		)	(124,189		)

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,
	2013			2012
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(21,100		)	(66,000		)
Long-term borrowings	75,000			20,000
Repayment of long-term debt	—			(20,000		)
Valencia's transactions with its owner	(13,477		)	(12,034		)
Dividends paid	(68,424		)	(18,076		)
Other, net	(1,727		)	(337		)
Net cash flows from financing activities	(29,728		)	(96,447		)
Change in Cash and Cash Equivalents	18,221			(12,086		)
Cash and Cash Equivalents at Beginning of Period	3,958			12,307
Cash and Cash Equivalents at End of Period	$	22,179		$	221
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	49,984		$	43,167
Income taxes paid (refunded), net	$	(44,999	)	$	(63,114	)

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 BALANCE SHEETS

(Unaudited)

	September 30, 2013		December 31, 2012
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	22,179	$	3,958
Accounts receivable, net of allowance for uncollectible accounts of $1,391 and $1,751	84,613		69,876
Unbilled revenues	46,473		49,085
Other receivables	52,328		50,975
Affiliate receivables	8,827		9,050
Materials, supplies, and fuel stock	57,534		56,790
Regulatory assets	34,315		36,490
Commodity derivative instruments	5,743		3,785
Income taxes receivable	35,910		80,223
Other current assets	32,294		27,457
Total current assets	380,216		387,689
Other Property and Investments:
Investment in PVNGS lessor notes	32,542		54,325
Investments held by NDT	207,483		188,971
Other investments	4,380		4,034
Non-utility property	976		976
Total other property and investments	245,381		248,306
Utility Plant:
Plant in service and plant held for future use	4,217,120		4,133,532
Less accumulated depreciation and amortization	1,409,042		1,355,240
	2,808,078		2,778,292
Construction work in progress	136,679		102,329
Nuclear fuel, net of accumulated amortization of $52,876 and $42,644	79,458		81,627
Net utility plant	3,024,215		2,962,248
Deferred Charges and Other Assets:
Regulatory assets	402,040		431,956
Goodwill	51,632		51,632
Commodity derivative instruments	4,284		352
Other deferred charges	84,702		81,724
Total deferred charges and other assets	542,658		565,664
	$	4,192,470	$	4,163,907

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, 2013			December 31, 2012
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Short-term debt	$	—		$	21,100
Accounts payable	60,049			73,914
Affiliate payables	13,462			25,340
Customer deposits	14,171			18,176
Accrued interest and taxes	52,735			30,320
Regulatory liabilities	1,218			15,172
Commodity derivative instruments	1,017			1,000
Dividends declared	132			132
Current portion of accumulated deferred income taxes	3,447			3,447
Other current liabilities	40,041			54,150
Total current liabilities	186,272			242,751
Long-term Debt	1,290,608			1,215,579
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	608,366			573,881
Accumulated deferred investment tax credits	12,598			14,242
Regulatory liabilities	409,444			379,841
Asset retirement obligations	92,614			85,042
Accrued pension liability and postretirement benefit cost	134,009			208,618
Commodity derivative instruments	1,347			1,933
Other deferred credits	87,417			95,585
Total deferred credits and liabilities	1,345,795			1,359,142
Total liabilities	2,822,675			2,817,472
Commitments and Contingencies (See Note 10)
Cumulative Preferred Stock
without mandatory redemption requirements ($100 stated value; 10,000,000 authorized; issued and outstanding 115,293 shares)	11,529			11,529
Equity:
PNM common stockholder's equity:
Common stock outstanding (no par value; 40,000,000 shares authorized; issued and outstanding 39,117,799 shares)	1,061,776			1,061,776
Accumulated other comprehensive income (loss), net of income taxes	(72,573		)	(81,414		)
Retained earnings	290,793			273,701
Total PNM common stockholder's equity	1,279,996			1,254,063
Non-controlling interest in Valencia	78,270			80,843
Total equity	1,358,266			1,334,906
	$	4,192,470		$	4,163,907

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 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, 2012	$	1,061,776	$	(81,414	)	$	273,701		$	1,254,063		$	80,843		$	1,334,906
Valencia's transactions with its owner	—		—			—			—			(13,477		)	(13,477		)
Net earnings	—		—			85,516			85,516			10,904			96,420
Total other comprehensive income	—		8,841			—			8,841			—			8,841
Dividends declared on preferred stock	—		—			(396		)	(396		)	—			(396		)
Dividends declared on common stock	—		—			(68,028		)	(68,028		)	—			(68,028		)
Balance at September 30, 2013	$	1,061,776	$	(72,573	)	$	290,793		$	1,279,996		$	78,270		$	1,358,266

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

20

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,
	2013			2012			2013			2012
	(In thousands)
Electric Operating Revenues	$	73,704		$	68,680		$	201,384		$	187,404
Operating Expenses:
Cost of energy	14,474			11,560			41,324			34,333
Administrative and general	10,641			10,130			32,446			30,700
Depreciation and amortization	13,850			13,819			37,810			37,173
Transmission and distribution costs	5,562			5,910			17,270			17,217
Taxes other than income taxes	6,923			6,291			17,558			16,322
Total operating expenses	51,450			47,710			146,408			135,745
Operating income	22,254			20,970			54,976			51,659
Other Income and Deductions:
Interest income	—			—			—			1
Other income	820			771			1,765			1,708
Other (deductions)	(104		)	(405		)	(356		)	(464		)
Net other income (deductions)	716			366			1,409			1,245
Interest Charges	6,655			7,047			20,661			21,214
Earnings before Income Taxes	16,315			14,289			35,724			31,690
Income Taxes	6,209			5,205			13,554			11,577
Net Earnings	$	10,106		$	9,084		$	22,170		$	20,113

The accompanying notes, as they relate to TNMP, 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 COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Net Earnings	$	10,106		$	9,084		$	22,170		$	20,113
Other Comprehensive Income (Loss):
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $128, $51, $127 and $150	(238		)	(92		)	(236		)	(270		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(19), $(16), $(54) and $(47)	35			29			99			85
Total Other Comprehensive Income (Loss)	(203		)	(63		)	(137		)	(185		)
Comprehensive Income	$	9,903		$	9,021		$	22,033		$	19,928

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,
	2013			2012
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	22,170		$	20,113
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	40,946			41,222
Deferred income tax expense	3,901			11,337
Other, net	(13		)	(275		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(9,608		)	(5,367		)
Materials and supplies	20			(365		)
Other current assets	(2,420		)	(709		)
Other assets	36			(498		)
Accounts payable	(291		)	(358		)
Accrued interest and taxes	14,669			4,860
Other current liabilities	(1,946		)	1,980
Other liabilities	2,182			(3,411		)
Net cash flows from operating activities	69,646			68,529
Cash Flows From Investing Activities:
Utility plant additions	(67,400		)	(59,801		)
Net cash flows from investing activities	(67,400		)	(59,801		)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	12,000			—
Short-term borrowings (repayments) – affiliate, net	4,800			2,300
Cash paid in debt exchange	(13,048		)	—
Dividends paid	(3,726		)	(11,028		)
Other, net	(2,117		)	—
Net cash flows from financing activities	(2,091		)	(8,728		)
Change in Cash and Cash Equivalents	155			—
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	156		$	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	13,626		$	13,074
Income taxes paid, net	$	696		$	1,848
Supplemental schedule of noncash financing activities:
Premium on long-term debt incurred in connection with debt exchange	$	23,249

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, 2013		December 31, 2012
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	156	$	1
Accounts receivable	26,324		17,217
Unbilled revenues	8,682		8,181
Other receivables	1,728		2,359
Materials and supplies	2,833		2,853
Regulatory assets	4,196		2,630
Current portion of accumulated deferred income taxes	1,131		1,131
Other current assets	1,816		1,107
Total current assets	46,866		35,479
Other Property and Investments:
Other investments	281		281
Non-utility property	2,240		2,240
Total other property and investments	2,521		2,521
Utility Plant:
Plant in service and plant held for future use	1,048,474		1,009,108
Less accumulated depreciation and amortization	347,228		339,315
	701,246		669,793
Construction work in progress	27,112		19,801
Net utility plant	728,358		689,594
Deferred Charges and Other Assets:
Regulatory assets	149,567		123,621
Goodwill	226,665		226,665
Other deferred charges	8,610		8,349
Total deferred charges and other assets	384,842		358,635
	$	1,162,587	$	1,086,229

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, 2013			December 31, 2012
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Short-term debt	$	12,000		$	—
Short-term debt – affiliate	33,100			28,300
Current installments of long-term debt	50,000			—
Accounts payable	7,114			8,848
Affiliate payables	2,138			4,381
Accrued interest and taxes	45,160			30,491
Other current liabilities	9,614			8,854
Total current liabilities	159,126			80,874
Long-term Debt	286,128			311,589
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	167,674			163,710
Regulatory liabilities	46,754			43,619
Asset retirement obligations	778			732
Accrued pension liability and postretirement benefit cost	13,433			15,947
Other deferred credits	6,573			5,944
Total deferred credits and other liabilities	235,212			229,952
Total liabilities	680,466			622,415
Commitments and Contingencies (See Note 10)
Common Stockholder's Equity:
Common stock outstanding ($10 par value; 12,000,000 shares authorized;
issued and outstanding 6,358 shares)	64			64
Paid-in-capital	390,366			390,366
Accumulated other comprehensive income (loss), net of income taxes	(353		)	(216		)
Retained earnings	92,044			73,600
Total common stockholder's equity	482,121			463,814
	$	1,162,587		$	1,086,229

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		AOCI			Retained Earnings			Total Common Stockholder's Equity
	(In thousands)
Balance at December 31, 2012	$	64	$	390,366	$	(216	)	$	73,600		$	463,814
Net earnings	—		—		—			22,170			22,170
Total other comprehensive income	—		—		(137		)	—			(137		)
Dividends declared on common stock	—		—		—			(3,726		)	(3,726		)
Balance at September 30, 2013	$	64	$	390,366	$	(353	)	$	92,044		$	482,121

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, 2013 and December 31, 2012, the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2013 and 2012, and the consolidated cash flows for the nine months ended September 30, 2013 and 2012. 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 2012 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2013 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 2012 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 the PVNGS Capital Trust and Valencia. 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.

PNMR shared services' administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 12.

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 $0.165 per share in July 2013 and $0.145 in July 2012, 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 $0.165 per share in September 2013 and $0.145 in September 2012, which are reflected as being in the third quarter within "Dividends Declared per Common Share" on the PNMR Condensed Consolidated Statements of Earnings.

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)

PNM declared and paid cash dividends on its common stock to PNMR of $68.0 million in the nine months ended September 30, 2013. PNM declared a cash dividend on its common stock to PNMR of $16.8 million in September 2012, which was paid in October 2012, and declared and paid a dividend of $17.7 million in June 2012. TNMP declared and paid cash dividends to PNMR of $3.7 million and $11.0 million in the nine months ended September 30, 2013 and 2012. TNMP dividends paid in 2012 were recorded as reductions of paid-in-capital.

New Accounting Pronouncements

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

Accounting Standards Update 2013-11 - Income Taxes: Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

The FASB released guidance that requires entities to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for net operating losses in certain circumstances. The guidance is to be applied prospectively and is effective for annual and interim reporting periods beginning after December 15, 2013, with early adoption permitted. The Company is still analyzing the impacts of this new standard and when to adopt it. However, it appears that the new standard will result in substantially all of the Company's liability for unrecognized tax benefits being reclassified from being reflected in liability accounts to being reflected as reductions of deferred tax assets. Adoption of this standard is not expected to impact earnings.

(2) Segment Information

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

PNM

PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also provides generation service to firm-requirements wholesale customers and sells electricity into the general 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 excluded from retail rates. FERC has jurisdiction over wholesale 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 PNMR Services Company.

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.

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)

PNMR SEGMENT INFORMATION

	PNM			TNMP			Corporate and Other			Consolidated
Three Months Ended September 30, 2013	(In thousands)
Electric operating revenues	$	326,026		$	73,704		$	—		$	399,730
Cost of energy	100,200			14,474			—			114,674
Margin	225,826			59,230			—			285,056
Other operating expenses	104,730			23,126			(3,282		)	124,574
Depreciation and amortization	25,879			13,850			3,014			42,743
Operating income	95,217			22,254			268			117,739
Interest income	2,298			—			(34		)	2,264
Other income (deductions)	2,211			716			(3,455		)	(528		)
Net interest charges	(20,124		)	(6,655		)	(3,586		)	(30,365		)
Segment earnings (loss) before income taxes	79,602			16,315			(6,807		)	89,110
Income taxes (benefit)	27,652			6,209			(3,565		)	30,296
Segment earnings (loss)	51,950			10,106			(3,242		)	58,814
Valencia non-controlling interest	(4,127		)	—			—			(4,127		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	47,691		$	10,106		$	(3,242	)	$	54,555
Nine Months Ended September 30, 2013
Electric operating revenues	$	863,609		$	201,384		$	—		$	1,064,993
Cost of energy	283,715			41,324			—			325,039
Margin	579,894			160,060			—			739,954
Other operating expenses	311,372			67,274			(10,192		)	368,454
Depreciation and amortization	77,763			37,810			9,616			125,189
Operating income	190,759			54,976			576			246,311
Interest income	7,839			—			(108		)	7,731
Other income (deductions)	6,977			1,409			(7,390		)	996
Net interest charges	(59,971		)	(20,661		)	(11,647		)	(92,279		)
Segment earnings (loss) before income taxes	145,604			35,724			(18,569		)	162,759
Income taxes (benefit)	49,184			13,554			(4,138		)	58,600
Segment earnings (loss)	96,420			22,170			(14,431		)	104,159
Valencia non-controlling interest	(10,904		)	—			—			(10,904		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	85,120		$	22,170		$	(14,431	)	$	92,859
At September 30, 2013:
Total Assets	$	4,192,470		$	1,162,587		$	73,757		$	5,428,814
Goodwill	$	51,632		$	226,665		$	—		$	278,297
Additions to utility and non-utility plant included in accounts payable	$	15,995		$	544		$	1,668		$	18,207

29

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	PNM			TNMP			Corporate and Other			Consolidated
Three Months Ended September 30, 2012	(In thousands)
Electric operating revenues	$	321,731		$	68,680		$	—		$	390,411
Cost of energy	99,217			11,560			—			110,777
Margin	222,514			57,120			—			279,634
Other operating expenses	101,104			22,331			(4,771		)	118,664
Depreciation and amortization	24,437			13,819			4,564			42,820
Operating income	96,973			20,970			207			118,150
Interest income	3,173			—			(43		)	3,130
Other income (deductions)	5,210			366			(827		)	4,749
Net interest charges	(19,230		)	(7,047		)	(4,238		)	(30,515		)
Segment earnings (loss) before income taxes	86,126			14,289			(4,901		)	95,514
Income taxes (benefit)	31,235			5,205			(2,902		)	33,538
Segment earnings (loss)	54,891			9,084			(1,999		)	61,976
Valencia non-controlling interest	(3,980		)	—			—			(3,980		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	50,779		$	9,084		$	(1,999	)	$	57,864
Nine Months Ended September 30, 2012
Electric operating revenues	$	832,242		$	187,404		$	—		$	1,019,646
Cost of energy	263,009			34,333			—			297,342
Margin	569,233			153,071			—			722,304
Other operating expenses	311,468			64,239			(12,676		)	363,031
Depreciation and amortization	72,017			37,173			13,099			122,289
Operating income (loss)	185,748			51,659			(423		)	236,984
Interest income	9,938			1			(131		)	9,808
Other income (deductions)	9,201			1,244			(4,797		)	5,648
Net interest charges	(56,652		)	(21,214		)	(12,414		)	(90,280		)
Segment earnings (loss) before income taxes	148,235			31,690			(17,765		)	162,160
Income taxes (benefit)	51,929			11,577			(8,897		)	54,609
Segment earnings (loss)	96,306			20,113			(8,868		)	107,551
Valencia non-controlling interest	(10,699		)	—			—			(10,699		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	85,211		$	20,113		$	(8,868	)	$	96,456
At September 30, 2012:
Total Assets	$	4,073,331		$	1,060,062		$	126,814		$	5,260,207
Goodwill	$	51,632		$	226,665		$	—		$	278,297
Additions to utility and non-utility plant included in accounts payable	$	6,056		$	886		$	1,063		$	8,005

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)

(3) Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2013 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	Unrealized						Fair Value
	Gain on			Pension			Adjustment
	Investment			Liability			for Cash Flow
	Securities			Adjustment			Hedges			Total
	(In thousands)
PNMR
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	(216	)	$	(81,630	)
Amounts reclassified from AOCI (pre-tax)	(9,190		)	4,773			153			(4,264		)
Income tax impact of amounts reclassified	3,639			(1,893		)	(54		)	1,692
Other OCI changes (pre-tax)	19,056			—			(363		)	18,693
Income tax impact of other OCI changes	(7,544		)	—			127			(7,417		)
Net change after income taxes	5,961			2,880			(137		)	8,704
Balance at September 30, 2013	$	22,367		$	(94,940	)	$	(353	)	$	(72,926	)

PNM
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	—	$	(81,414	)
Amounts reclassified from AOCI (pre-tax)	(9,190		)	4,773			—		(4,417		)
Income tax impact of amounts reclassified	3,639			(1,893		)	—		1,746
Other OCI changes (pre-tax)	19,056			—			—		19,056
Income tax impact of other OCI changes	(7,544		)	—			—		(7,544		)
Net change after income taxes	5,961			2,880			—		8,841
Balance at September 30, 2013	$	22,367		$	(94,940	)	$	—	$	(72,573	)

TNMP
Balance at December 31, 2012	$	—	$	—	$	(216	)	$	(216	)
Amounts reclassified from AOCI (pre-tax)	—		—		153			153
Income tax impact of amounts reclassified	—		—		(54		)	(54		)
Other OCI changes (pre-tax)	—		—		(363		)	(363		)
Income tax impact of other OCI changes	—		—		127			127
Net change after income taxes	—		—		(137		)	(137		)
Balance at September 30, 2013	$	—	$	—	$	(353	)	$	(353	)

Pre-tax amounts reclassified from AOCI related to "Unrealized Gain on Investment Securities" are included in "Gains on investments held by NDT" 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. Approximately 19.6% of the amount reclassified is then capitalized into construction work in process and approximately 1.1% is 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 is then capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in "Income Taxes" in the Condensed Consolidated Statements of Earnings.

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)

(4) Variable Interest Entities

GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, including determining the primary beneficiary of a variable interest entity, by 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. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. Additional information concerning PNM's variable interest entities is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

Valencia

PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 145 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 operations and maintenance charges under this PPA. For the three and nine months ended September 30, 2013, PNM paid $4.8 million and $14.1 million for fixed charges and $0.7 million and $1.0 million for variable charges. For the three and nine months ended September 30, 2012, PNM paid $4.8 million and $14.0 million for fixed charges and $0.6 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 variable interest entity and that PNM is the primary beneficiary of the entity under GAAP. As the primary beneficiary, PNM consolidates the entity 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.

During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity.

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 will be initiated if the parties fail to reach agreement on fair market value within 60 days. After the purchase price has been determined, PNM may in its sole discretion determine whether or not it desires to exercise its option to purchase the 50% interest. In that regard, PNM will evaluate all its alternatives with respect to Valencia with the goal of achieving a fair and economical benefit for its customers. Also, PNM is in the process of developing its 2014 IRP (Note 11). Through this process, PNM will evaluate all of its resource options including Valencia to determine the optimal way to serve its customers. If PNM decides to exercise its option, the approval of the NMPRC and FERC would be required, which process could take up to 15 months. Since the purchase price is yet to be established, PNM cannot determine whether or not it will exercise its option or if required regulatory approvals would be received.

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Operating revenues	$	5,453		$	5,358		$	15,150		$	14,916
Operating expenses	(1,326		)	(1,378		)	(4,246		)	(4,217		)
Earnings attributable to non-controlling interest	$	4,127		$	3,980		$	10,904		$	10,699

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)

Financial Position

	September 30,		December 31,
	2013		2012
	(In thousands)
Current assets	$	3,457	$	3,655
Net property, plant, and equipment	75,841		77,953
Total assets	79,298		81,608
Current liabilities	1,028		765
Owners' equity – non-controlling interest	$	78,270	$	80,843

PVNGS Leases

PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. PNM is not the legal or tax owner of the leased assets. PNM has an option to purchase the leased assets at appraised value at the end of the leases, but does not have a fixed price purchase option and does not provide residual value guarantees. As set forth in the leases, PNM has options to renew the leases at fixed rates, which represent 50% of the amounts during the original terms of the leases, for two years beyond the termination of the original lease terms. The option periods on all of the Unit 1 leases and one of the Unit 2 leases, amounting to 14% of the Unit 2 capacity under lease, may be further extended for up to an additional six years (the "Maximum Option Period") if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K, PNM notified each of the lessors of the Unit 1 leases that it will extend each Unit 1 lease for the Maximum Option Period upon the expiration of the basic lease term on January 15, 2015. In addition, PNM notified each of the lessors in the Unit 2 leases that PNM will "retain" the assets leased under that lease upon the expiration of the basic lease term on January 15, 2016. PNM will be required to specify by notice to each of the lessors by January 15, 2014, whether on January 15, 2016 it will extend the Unit 2 leases or purchase the leased assets. PNM is unable to predict the outcome or impact of these matters.

PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes, aggregate $52.6 million as of September 30, 2013 over the remaining original terms of the leases. Under certain circumstances (for example, final shutdown of the plant, 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 beneficial owners and take title to the leased interests. If such an event had occurred as of September 30, 2013, PNM could have been required to pay the beneficial owners up to $154.1 million, which would result in PNM taking ownership of the leased assets and termination of the leases. PNM has no other financial obligations or commitments to the trusts or the beneficial owners. 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 evaluated the PVNGS lease arrangements, including the notices discussed above, and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP. PNM has recorded no assets or liabilities related to the trusts other than the accrual of lease payments between the scheduled payment dates, which were $11.8 million at September 30, 2013 and $26.0 million at December 31, 2012, that are included in other current liabilities on the Condensed Consolidated Balance Sheets. For additional information regarding these leases, see Risk Factors, MD&A – Off Balance Sheet Arrangements and Note 7 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

Delta

PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. PNM also controls the dispatch of the generating plant, which impacts the variable payments made under the PPA and impacts the economic performance of the entity that owns Delta. PNM makes fixed and variable payments to Delta under the PPA. For the three and nine months ended

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)

September 30, 2013, PNM incurred fixed capacity charges of $1.6 million and $4.8 million and variable energy charges of $0.7 million and $1.3 million under the PPA. For the three and nine months ended September 30, 2012, PNM incurred fixed capacity charges of $1.6 million and $4.7 million and variable energy charges of $0.3 million and $0.6 million. PNM's only quantifiable obligation under the PPA is to make the fixed payments, which as of September 30, 2013, aggregated $40.7 million through the end of the PPA in 2020. PNM will also pay variable costs, which cannot be quantified since the amounts are based on how much the generating plant is in operation.

This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it is the primary beneficiary of the entity that owns Delta, or to consolidate that entity if it were determined that PNM is the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.

In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owns Delta. At closing PNM would make a cash payment of $23.0 million, which would be adjusted for actual working capital compared to a targeted working capital and certain prepayments of debt. Delta had project financing debt, which PNM would retire at closing of the purchase, of $16.9 million at September 30, 2013, including $3.2 million due by September 30, 2014. FERC approved the purchase on February 26, 2013 and the NMPRC approved the purchase on June 26, 2013. Closing is subject to the seller remedying specified operational, NERC compliance, and environmental issues, as well as other customary closing conditions. Closing of the purchase is anticipated to occur in early 2014.

Delta informed PNM that at September 30, 2013, it had total assets of $25.3 million, including net property, plant, and equipment of $21.0 million, and total liabilities of $18.9 million. Delta also indicated its revenue for the three and nine months ended September 30, 2013 was $2.8 million and $6.8 million and its net earnings were $0.6 million and $0.9 million. Consolidation of Delta would be immaterial to the Condensed Consolidated Balance Sheets of PNMR and PNM. Since all of Delta's revenues and expenses are attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Condensed Consolidated Statements of Earnings of PNMR and PNM would be to reclassify Delta's net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM.

(5) Fair Value of Derivative and Other Financial Instruments

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. The Company'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. 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, to the extent not covered by the FPPAC. 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. Additional information concerning the Company's energy related derivative contracts, including how commodity risk is managed, is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

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.

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)

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. Energy contracts that meet the definition of a derivative under GAAP and do not qualify, or are not designated, for the normal sales and purchases exception are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met and elected. Normal sales and purchases are not marked to market and are reflected in results of operations when the underlying transactions physically settle.

During the nine months ended September 30, 2013 and the year ended December 31, 2012, 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 economic hedge. The Company does not enter into speculative trading transactions.

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

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, 2013			December 31, 2012
PNMR and PNM	(In thousands)
Current assets	$	5,743		$	3,785
Deferred charges	4,284			352
	10,027			4,137
Current liabilities	(1,017		)	(1,000		)
Long-term liabilities	(1,347		)	(1,933		)
	(2,364		)	(2,933		)
Net	$	7,663		$	1,204

Included in the above table are $2.3 million of current assets and $3.8 million of deferred charges related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium. Certain of PNM's commodity derivative instruments included 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

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)

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, 2013 and December 31, 2012.

At September 30, 2013 and December 31, 2012, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at September 30, 2013 and December 31, 2012, amounts posted as cash collateral under margin arrangements were $2.0 million and $1.9 million for both PNMR and PNM. PNMR and PNM had no obligation to return cash collateral at September 30, 2013 and December 31, 2012. Cash collateral amounts are included in other current assets 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 $0.6 million of current assets, $0.1 million of deferred charges and $0.1 million of current liabilities at September 30, 2013 and less than $0.1 million of current assets at December 31, 2012 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 on earnings, excluding income tax effects and settlements, of commodity derivative instruments that are recorded at fair value. Commodity derivatives had no impact on OCI for the periods presented.

	Economic Hedges
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013		2012
PNMR and PNM	(In thousands)
Electric operating revenues	$	7,077		$	(740	)	$	5,743	$	897
Cost of energy	(72		)	263			421		(278		)
Total gain (loss)	$	7,005		$	(477	)	$	6,164	$	619

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
September 30, 2013
PNMR and PNM	980,000	(3,801,738	)
December 31, 2012
PNMR and PNM	1,127,500	(2,477,520	)

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

The table below presents information about the Company's contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company's revolving credit facilities that have been issued as

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)

collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and 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)
September 30, 2013
PNMR and PNM	$	2,250	$	—	$	2,224
December 31, 2012
PNMR and PNM	$	2,933	$	—	$	2,777

Sale of Power from PVNGS Unit 3

Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of September 30, 2013, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium.  PNM has established fixed rates for substantially all of these sales through the end of 2013 through derivative contracts that are accounted for as economic hedges. PNM is also substantially hedged for 2014.

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, which include unrealized gains on securities which have not been recognized in net earnings. 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 a trust for PNM's share of post-term reclamation

costs related to the coal mines serving SJGS, which investments are included in "other investments" on the Condensed Consolidated Balance Sheet. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	September 30, 2013				December 31, 2012
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Cash and cash equivalents	$	—	$	24,414	$	—	$	4,628
Equity securities:
Domestic value	10,519		34,967		5,223		30,044
Domestic growth	23,355		67,527		15,212		51,650
International and other	1,543		16,159		247		14,868
Fixed income securities:
U.S. Government	262		16,711		1,305		32,592
Municipals	1,120		37,074		4,069		43,861
Corporate and other	221		14,553		1,100		14,868
	$	37,020	$	211,405	$	27,156	$	192,511

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)

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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In thousands)
Proceeds from sales	$	103,230		$	90,518		$	179,336		$	136,305
Gross realized gains	$	2,611		$	6,263		$	8,962		$	11,029
Gross realized (losses)	$	(1,202	)	$	(5,131	)	$	(2,920	)	$	(7,055	)

Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. Held-to-maturity securities consist of the investment in PVNGS lessor notes and certain items within other investments.

At September 30, 2013, 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		PNM
	(In thousands)
Within 1 year	$	1,284	$	4,840	$	1,138
After 1 year through 5 years	16,768		55,310		53,956
After 5 years through 10 years	8,027		—		—
After 10 years through 15 years	3,277		—		—
After 15 years through 20 years	5,512		—		—
After 20 years	33,470		—		—
	$	68,338	$	60,150	$	55,094

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.

Fair Value Disclosures

The Company determines the fair values of its derivative and other 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 can 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.

For the NDT and reclamation trust investments, 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 long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and other investments, fair values were determined by

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)

discounted cash flow models that take into consideration discount rates that are observable for similar type assets and liabilities. Management of the Company independently verifies the information provided by pricing services.

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, 2013 and 2012.

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2013	(In thousands)
PNMR and PNM
Decommissioning and reclamation investments:
Cash and cash equivalents	$	24,414		$	24,414	$	—
Equity securities:
Domestic value	34,967			34,967		—
Domestic growth	67,527			67,527		—
International and other	16,159			16,159		—
Fixed income securities:
U.S. government	16,711			14,949		1,762
Municipals	37,074			—		37,074
Corporate and other	14,553			—		14,553
	$	211,405		$	158,016	$	53,389
Commodity derivative assets	$	10,027		$	—	$	10,027
Commodity derivative liabilities	(2,364		)	—		(2,364		)
Net	$	7,663		$	—	$	7,663
December 31, 2012
PNMR and PNM
Decommissioning and reclamation investments:
Cash and cash equivalents	$	4,628		$	4,628	$	—
Equity securities:
Domestic value	30,044			30,044		—
Domestic growth	51,650			51,650		—
International and other	14,868			14,868		—
Fixed income securities:
U.S. government	32,592			27,737		4,855
Municipals	43,861			—		43,861
Corporate and other	14,868			—		14,868
	$	192,511		$	128,927	$	63,584
Commodity derivative assets	$	4,137		$	—	$	4,137
Commodity derivative liabilities	(2,933		)	—		(2,933		)
Net	$	1,204		$	—	$	1,204

There were no Level 3 fair value measurements at September 30, 2013 or December 31, 2012.

39

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The carrying amounts and fair values of investments in 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, 2013	(In thousands)
PNMR
Long-term debt	$	1,748,841	$	1,929,828	$	—	$	1,926,126	$	3,702
Investment in PVNGS lessor notes	$	53,300	$	55,094	$	—	$	—	$	55,094
Other investments	$	2,803	$	6,941	$	739	$	—	$	6,202
PNM
Long-term debt	$	1,290,608	$	1,400,109	$	—	$	1,400,109	$	—
Investment in PVNGS lessor notes	$	53,300	$	55,094	$	—	$	—	$	55,094
Other investments	$	458	$	458	$	458	$	—	$	—
TNMP
Long-term debt	$	336,128	$	393,122	$	—	$	393,122	$	—
Other investments	$	281	$	281	$	281	$	—	$	—
December 31, 2012
PNMR
Long-term debt	$	1,672,290	$	1,969,362	$	—	$	1,966,725	$	2,637
Investment in PVNGS lessor notes	$	77,682	$	84,198	$	—	$	—	$	84,198
Other investments	$	5,599	$	6,965	$	774	$	—	$	6,191
PNM
Long-term debt	$	1,215,579	$	1,385,433	$	—	$	1,385,433	$	—
Investment in PVNGS lessor notes	$	77,682	$	84,198	$	—	$	—	$	84,198
Other investments	$	494	$	494	$	494	$	—	$	—
TNMP
Long-term debt	$	311,589	$	418,166	$	—	$	418,166	$	—
Other investments	$	281	$	281	$	281	$	—	$	—

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)

(6) 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,
	2013		2012		2013		2012
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	54,555	$	57,864	$	92,859	$	96,456
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	177		114		194		156
Average Shares - Basic	79,831		79,768		79,848		79,810
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	503		622		608		600
Average Shares - Diluted	80,334		80,390		80,456		80,410
Net Earnings Per Share of Common Stock:
Basic	$	0.68	$	0.73	$	1.16	$	1.21
Diluted	$	0.68	$	0.72	$	1.15	$	1.20

⁽¹⁾  Excludes the effect of out-of-the-money options for 793,010 shares of common stock at September 30, 2013.

(7) 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"). In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted in 2013 or 2012 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets and have service requirements. 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 2012 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, certain 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 stock awards.

The stock-based compensation expense related to stock options and restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However, compensation expense for awards to participants that are retirement eligible on the award date is recognized immediately at the award date and is not amortized. 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, 2013 and December 31, 2012, PNMR had unrecognized expense related to stock awards of $5.7 million and $3.8 million. 

41

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company uses the Black Scholes option pricing model to estimate the fair value of stock option awards based on multiple factors, including historical exercise patterns of employees in relatively homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected exercising patterns for these same homogeneous groups, and both the implied and historical volatility of PNMR's stock price. 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 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.

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	2013			2012
Expected quarterly dividends per share	$	0.165		$	0.145
Risk-free interest rate	0.34		%	0.65		%
Market-Based Shares
Dividend yield	2.86		%	3.45		%
Expected volatility	25.11		%	43.98		%
Risk-free interest rate	0.36		%	1.04		%

The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the nine months endedSeptember 30, 2013:

	Stock Option Shares		Weighted- Average Exercise Price		Restricted Stock		Weighted- Average Grant Date Fair Value
Outstanding at beginning of period	1,992,700		$	20.72	353,722		$	14.03
Granted	—		$	—	249,113		$	20.03
Exercised	(260,579	)	$	13.43	(275,988	)	$	15.92
Forfeited	—		$	—	(8,366	)	$	18.37
Expired	(292,644	)	$	27.23	—		$	—
Outstanding at end of period	1,439,477		$	20.72	318,481		$	17.88

Included as restricted stock granted and exercised in the table above are 100,953 shares that were based upon achieving performance or market targets for 2012. The Board approved these shares in February 2013, including shares with market targets at near maximum levels.

PNMR also has share agreements that provide for performance or market targets through 2015. Excluded from the above table are maximums of 188,129, 198,369, and 179,811 restricted stock shares for periods ending in 2013, 2014, and 2015 that would be awarded if all performance or market criteria are achieved 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 the Company meets specific market targets at the end of 2016 and she remains an employee of the Company. If the Company achieves specific market targets at the end of 2014 and she remains an employee of the Company, she would receive 35,000 of the total shares at that time. The retention award

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)

was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include any shares under the retention award agreement.

At September 30, 2013, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.7 million with a weighted-average remaining contract life of 3.56 years. At September 30, 2013, the exercise price of 793,010 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

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

	Nine Months Ended September 30,
Stock Options	2013		2012
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	625	$	1,058
Total intrinsic value of options exercised (in thousands)	$	2,466	$	4,515
Restricted Stock
Weighted-average grant date fair value	$	20.03	$	15.63
Total fair value of restricted shares that vested (in thousands)	$	4,395	$	4,755

(8) Financing

Additional information concerning financing activities, including a TNMP cash-flow hedge that establishes a fixed interest rate on a variable rate loan, is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

Short-term Debt

PNMR has a revolving credit financing capacity of $300.0 million under the PNMR Revolving Credit Facility. PNM has a revolving credit financing capacity of $400.0 million under the PNM Revolving Credit Facility. Both of these facilities currently expire on October 31, 2018. In December 2012, PNMR borrowed $100.0 million under the PNMR Term Loan Agreement, which matures in December 2013. TNMP has a revolving credit financing capacity of $75.0 million under the TNMP Revolving Credit Facility that is secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. On September 18, 2013, the TNMP Revolving Credit Facility was amended and restated to extend its maturity from December 16, 2015 to September 18, 2018. At September 30, 2013, the weighted average interest rate was 1.31% for borrowings outstanding under the PNMR Term Loan Agreement, 1.44% for the PNM Term Loan Agreement, and 1.30% for the TNMP Revolving Credit Facility. Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2013		2012
	(In thousands)
PNM – Revolving credit facility	$	—	$	21,100
TNMP – Revolving credit facility	12,000		—
PNMR:
Revolving credit facility	—		37,600
PNMR Term Loan Agreement	100,000		100,000
	$	112,000	$	158,700

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)

At October 25, 2013, PNMR, PNM, and TNMP had $291.4 million, $396.8 million, and $67.7 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit. Total availability at October 25, 2013, on a consolidated basis, was $755.9 million for PNMR. As of October 25, 2013, TNMP had $43.0 million in borrowings from PNMR under their intercompany loan agreement. At October 25, 2013, PNMR, PNM and TNMP had consolidated invested cash of $6.5 million, $15.7 million, and none.

Financing Activities

On March 6, 2013, TNMP commenced an offer to exchange any and all of TNMP's $265.5 million aggregate principal amount outstanding 9.50% First Mortgage Bonds, due 2019, Series 2009A, for a new series of 6.95% First Mortgage Bonds, due 2043, Series 2013A, and up to $140 in cash for each $1,000 of bonds exchanged. Settlement of the exchange offer occurred on April 3, 2013. Upon settlement, TNMP issued $93.2 million of 6.95% First Mortgage Bonds and paid an aggregate of $13.0 million in cash in exchange for $93.2 million of 9.50% First Mortgage Bonds, in addition to payment of accrued and unpaid interest on the exchanged bonds. The exchange resulted in the recording of a $23.2 million premium on the 6.95% First Mortgage Bonds reflecting the contractual interest rate being in excess of the market rate of interest on the date of the exchange. A regulatory asset was recorded offsetting the premium and the cash consideration paid in the exchange.

On April 22, 2013, PNM entered into a $75.0 million Term Loan Agreement (the "PNM Term Loan Agreement") among PNM, the lenders identified therein, and Union Bank, N.A., as Administrative Agent. Funding of the PNM Term Loan Agreement occurred on April 22, 2013, at which time the funds were used to repay $75.0 million in borrowings made under the PNM Revolving Credit Facility. The PNM Term Loan Agreement bears interest at a variable rate, which was 1.44% at September 30, 2013, must be repaid on or before October 21, 2014, and is reflected as long-term debt on the Condensed Consolidated Balance Sheets. The PNM Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Term Loan Agreement has a cross default provision and a change of control provision.

In the nine months ended September 30, 2013, PNMR purchased $23.0 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, for $26.0 million plus accrued and unpaid interest.

On October 2, 2013, the NMPRC approved PNM's application to enter into a new revolving credit facility of up to $50.0 million with banks operating in New Mexico. PNM anticipates entering into a facility in late 2013.

In October 2013, the second of the two1-year extension options for the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility were exercised extending the expiration of both facilities to October 31, 2018.

(9) 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 ("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 2012 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.

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)

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
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	65		$	54		$	—	$	—
Interest cost	7,035			8,058			1,029			1,324			180		219
Expected return on plan assets	(10,482		)	(10,325		)	(1,261		)	(1,225		)	—		—
Amortization of net (gain) loss	3,710			2,629			1,061			972			58		21
Amortization of prior service cost	19			79			(336		)	(336		)	—		—
Net periodic benefit cost	$	282		$	441		$	558		$	789		$	238	$	240
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	195		$	162		$	—	$	—
Interest cost	21,106			24,174			3,085			3,972			540		657
Expected return on plan assets	(31,447		)	(30,975		)	(3,782		)	(3,675		)	—		—
Amortization of net (gain) loss	11,130			7,887			3,182			2,916			174		63
Amortization of prior service cost	57			237			(1,008		)	(1,008		)	—		—
Net periodic benefit cost	$	846		$	1,323		$	1,672		$	2,367		$	714	$	720

PNM made contributions to its pension plan trust of zero and $60.0 million in the three and nine months ended September 30, 2013 and zero and $77.7 million in the three and nine months ended September 30, 2012. PNM does not anticipate making additional contributions to its pension trust in 2013.  Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, PNM estimates minimum required contributions for its pension plan trust would total $49.1 million for 2014-2017. Minimum required contributions were developed using current funding assumptions, including discount rates of 4.8% to 5.2%. Actual amounts required to be funded in the future will depend 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, 2013 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2012. PNM expects contributions during 2013 to the OPEB trust to total $3.3 million.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.1 million in the three and nine months ended September 30, 2013 and $0.4 million and $1.1 million in the three and nine months ended September 30, 2012 and are expected to total $1.5 million during 2013.

45

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	75		$	61		$	—	$	—
Interest cost	772			909			141			156			9		11
Expected return on plan assets	(1,212		)	(1,331		)	(126		)	(129		)	—		—
Amortization of net (gain) loss	262			115			—			(52		)	—		—
Amortization of prior service cost	—			—			14			14			—		—
Net Periodic Benefit Cost (Income)	$	(178	)	$	(307	)	$	104		$	50		$	9	$	11
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	225		$	183		$	—	$	—
Interest cost	2,315			2,727			424			468			27		33
Expected return on plan assets	(3,637		)	(3,993		)	(377		)	(387		)	—		—
Amortization of net (gain) loss	787			345			—			(156		)	—		—
Amortization of prior service cost	—			—			43			42			—		—
Net Periodic Benefit Cost (Income)	$	(535	)	$	(921	)	$	315		$	150		$	27	$	33

TNMP made contributions to its pension plan trust of zero and $1.0 million in the three and nine months ended September 30, 2013 and zero and $5.3 million in the three and nine months ended September 30, 2012. TNMP does not anticipate making additional contributions to its pension trust in 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, TNMP estimates there would be no minimum required contributions to its pension plan trust for 2014-2017. Minimum required contributions were developed using current funding assumptions, including discount rates of 4.8% and 5.2%. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions to the OPEB trust of zero and $0.3 million in the three and nine months ended September 30, 2013 and zero and $0.3 million in the three and nine months ended September 30, 2012. TNMP does not anticipate making additional contributions to the OPEB trust in 2013. 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, 2013 and 2012 and are expected to total $0.1 million during 2013.

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)

(10)    Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company is also 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 occasionally enters into financial commitments in connection with its business operations. The Company is also involved in various legal and regulatory (Note 11) 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. Notwithstanding these facts, the Company has assessed these matters based on current information and made judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and 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. 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 2012 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 under the contract. In November 1997, the D.C. 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 PVNGS owners previously received a damages award for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007, through June 30, 2011, APS, as a co-owner of PVNGS, incurred additional damages due to DOE's continuing failure to remove spent nuclear fuel and high level waste from PVNGS. Activities in this legal proceeding are currently limited to review by the government of supporting information for APS's claim. PNM is unable to predict the outcome of this matter.

PNM estimates that it will incur approximately $42.8 million (in 2010 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, 2013 and December 31, 2012, PNM had a liability for interim storage costs of $12.4 million and $13.9 million included in other deferred credits.

On June 8, 2012, the D.C. 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. The D.C. Circuit found that the agency's 2010 Waste Confidence Decision update constituted a major federal action, which requires either an environmental impact statement

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)

or a finding of no significant impact from the agency's actions. The D.C. Circuit found that the NRC's evaluation of the environmental risks from spent nuclear was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action. In September 2012, the NRC issued a directive to its staff to proceed with development of a generic environmental impact statement to support an updated Waste Confidence Decision within 24 months. The petitioners had also sought a writ requiring the NRC to comply with the law and resume processing DOE's pending license application for a nuclear waste site at Yucca Mountain in Nevada. On August 13, 2013, the D.C. Circuit granted the writ and held that the NRC must continue reviewing the license application. PNM is unable to predict the impact of these decisions.

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 Determination Process - SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology ("SNCR"). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that requires installation of selective catalytic reduction technology ("SCR") with stringent NOx emission limits on all four units by September 21, 2016.

PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA's decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule on March 1, 2012. These parties have also formally asked EPA to stay the effective date of the rule. Several environmental groups have intervened in support of EPA. WEG also filed an action to challenge EPA's rule in the Tenth Circuit, seeking to shorten its compliance period from five years to three years and PNM has intervened in this action. Oral arguments on the merits of the FIP challenges were held in October 2012 in the Tenth Circuit. In accordance with the court's order, the parties have filed supplemental information. No decision has been announced and there is no deadline for a court decision.

In litigation involving several environmental groups, the United States District Court for the District of Columbia entered a consent decree, which, as amended, required EPA to issue a final rulemaking on New Mexico's regional haze SIP by November 15, 2012. EPA approved all components of the SIP, except for the NOx BART determination for SJGS. With respect to that element of the SIP, EPA determined that with the FIP in place, it had met its obligation under the consent decree.

Because the unchanged compliance deadline of the FIP required PNM to continue to take steps to commence installation of SCRs at SJGS, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, has been suspended through November 1, 2014. PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million, which amounts include costs for construction management, gross receipts taxes, AFUDC, and other PNM costs, although final costs would be refined

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)

through an "open book" subcontractor bidding process. The costs for the project to install SCRs would encompass installation of technology to comply with the NAAQS requirements described below.

PNM previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS. The estimates for SNCRs and the NAAQS requirements include gross receipts taxes, AFUDC, and other PNM costs.

Based upon its current SJGS ownership interest, PNM's share of the costs under either SCRs or SNCRs as described above would be about 46.3%.

During 2012 and early 2013, PNM engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS, subject to approval by EIB and EPA. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP.

NMPRC approval of the retirement of SJGS Units 2 and 3 and plans for PNM to acquire power to replace its reduced capacity from SJGS would also be part of implementation. PNM also anticipates requesting approval to recover from ratepayers the unrecovered investment in SJGS Units 2 and 3 and costs incurred to retire those units. PNM anticipates filing for the required NMPRC approvals in December 2013. On July 10, 2013, the NMPRC issued an order initiating a proceeding regarding the possible retirement of SJGS Units 2 and 3 and impacts on service reliability, and other items. The order requires PNM to make monthly presentations to the NMPRC on this matter. At September 30, 2013, PNM's net book value of SJGS Units 2 and 3 was approximately $287 million.

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013, reflecting the terms of the non-binding agreement, including the installation of SNCRs on Units 1 and 4 and the retirement of Units 2 and 3. NMED developed a revised SIP and submitted it to the EIB for approval in May 2013. After a public hearing, the EIB approved the revised SIP in September 2013 and the revised SIP was submitted to EPA for approval on October 18, 2013. EPA action on the revised SIP is projected for late 2014.

Due to the long lead times on certain equipment purchases, PNM is taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In April 2013, PNM issued an RFP for SNCR system design and technology. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider, but has not yet entered into a construction and procurement contract.

In connection with the implementation of the revised plan, retirement of SJGS Units 2 and 3 could result in shifts in ownership among SJGS owners as may be agreed upon by the owners. See SJGS Ownership Restructuring Matters below. Owners of the affected units also may seek approvals of their utility commissions or governing boards.

This revised plan primarily focuses on how SJGS would meet the regional haze rule, but also indicates that PNM would build a natural gas-fired generating plant to be sited at SJGS to partially replace the capacity from the retired coal units. Detailed replacement power strategies also would be finalized.  PNM believes adequate replacement power alternatives will be available to meet its generation needs and ensure reliability.

Contemporaneously with the signing of the non-binding agreement, EPA indicated in writing that if the terms agreed to do not move forward due to circumstances outside of the control of PNM and NMED, EPA will work with the State of New Mexico and PNM to create a reasonable FIP compliance schedule to reflect the time used to develop the revised SIP.

On February 25, 2013, the parties filed their status reports with the Tenth Circuit.  To demonstrate that progress has been made toward settling the Tenth Circuit litigation, information, including the non-binding agreement and its accompanying timeline, was submitted to the Tenth Circuit. Following the parties' submission of their status reports, on February 28, 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals. On October 17, 2013, the court ruled on a motion filed by PNM

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)

for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously filed motion to stay the EPA rule. The court placed the pending petitions for review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the agreement in principle fails or is not implemented as was indicated in the term sheet and timeline, any party to the litigation may file a motion seeking to lift the abatement.  PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

If the February 15, 2013 plan described above is implemented, PNM currently estimates its share of the costs to install SNCRs and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 would be approximately $60 million to $80 million, including gross receipts taxes, AFUDC, and other PNM costs. This amount is based on the anticipation that PNM's ownership share of SJGS Units 1 and 4 would aggregate to between approximately 52% and 55%. PNM also estimates that the cost of replacing a portion of PNM's share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3 with identified gas-fired or solar peaking capacity would be approximately $299 million. Neither of these amounts is included in PNM's current construction expenditure forecast since approval of the plan is subject to numerous conditions. Additional base load generating capacity may be required to replace a portion of retired SJGS capacity. The nature of additional base load capacity, which has not yet been identified, could come from some combination of PVNGS Unit 3, renewable resources, and/or additional gas-fired generation. 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 would increase with the installation of either SCRs or SNCRs. See Note11 for additional information concerning PNM's filing for NMPRC approvals regarding these matters.

PNM can provide no assurance that the requirements of the plan agreed to on February 15, 2013 will be accomplished at all or within the required timeframes. If the February 15, 2013 plan is not implemented, PNM would seek to work with NMED and EPA to develop a revised timetable for implementation of the FIP. If an agreement on a revised timetable cannot be reached, PNM will likely be unable to complete the installation of SCRs on all four units at SJGS by the FIP deadline of September 21, 2016. In such event, PNM would likely seek relief from the compliance deadline from EPA or the Tenth Circuit in order to continue to be able to operate the plant during the completion of the installation process. If relief is not granted, PNM could be forced to temporarily cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire temporary replacement power through short-term or open-market purchases in order to serve the needs of its customers. There can be no assurance that sufficient replacement power will be available to serve PNM's needs or, if available, what costs would be incurred.

PNM is unable to predict the ultimate outcome of these matters or what additional pollution control equipment will be required at SJGS.PNM will seek recovery from its ratepayers for all costs that may be incurred as a result of the CAA requirements. Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance the installation. It is possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation or legislation, if any, 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.

SJGS Ownership Restructuring Matters - As discussed in the 2012 Annual Reports on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The San Juan Project Participation Agreement ("SJPPA") that governs the operation of SJGS expires on July 1, 2022 and the contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. Accordingly, they believe they would be unable to fund the construction of either SCRs or SNCRs at SJGS. Therefore, the California participants have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA and sooner, if possible. One other participant has also expressed a similar intent to exit ownership in the plant.

The SJGS participants have engaged in negotiations concerning the implementation of the revised SIP to address BART at SJGS. The negotiations have included potential shifts in ownership among participants and between units in order to facilitate the shutdown of SJGS Units 2 and 3 to comply with the revised SIP and to accommodate the intent of the participants desiring to exit ownership in SJGS. This could result in the exiting participants' ownership interests in SJGS Unit 4 being shifted to SJGS Unit 3 and certain of the continuing participants, including PNM, acquiring additional ownership interests in Unit 4. In addition,

50

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

the discussions regarding such a restructuring have included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs. Although discussions are continuing, no agreements have been reached.

The SJPPA requires PNM, as operating agent, to obtain approval of capital improvement project expenditures from participants who have an ownership interest in the relevant unit or common property. As provided in the SJPPA, specified percentages of both the outstanding participant shares, based on MW ownership, and the number of participants in the unit or common property must be obtained in order for a capital improvement project to be approved. PNM presented the SNCR project, including NAAQS compliance requirements, to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. The SJPPA provides that PNM is authorized and obligated to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM is evaluating its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants, but has not reached a decision on how to proceed. PNM cannot predict the outcome of this matter, its impact on SJGS' compliance with the CAA, or the impact on PNM's financial position and results of operations.

Four Corners

On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule includes two compliance alternatives. The first emission control strategy finalized by EPA would require the installation of post-combustion controls, including SCRs, on each of Units 1-5 at Four Corners to reduce NOx emissions. Under the second emission control alternative, the owners of Four Corners would have the option to close permanently 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. 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. Under the EPA's final BART determination, the Four Corners participants had until July 1, 2013 to notify EPA of which emission control strategy Four Corners would follow. Either alternative would involve substantial investment by the owners in additional post-combustion pollution controls and, accordingly, contemplates the continued operation of Four Corners for a substantial period of time. On September 24, 2013, EPA extended the date by which the Four Corners participants must notify EPA of their chosen BART compliance strategy from July 1 to December 31, 2013.

The Four Corners participants' obligations to comply with EPA's final BART determinations, coupled with the financial impact of possible future 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.

PNM is continuing to evaluate the impacts of EPA's BART determination for Four Corners. PNM estimates its share of costs, including PNM's AFUDC, to be up to approximately $75 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM has no ownership interest in Four Corners Units 1, 2, and 3. PNM is unable to predict the ultimate outcome of this matter.

SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at Four Corners. APS and SCE entered into an asset purchase agreement, providing for the purchase by APS of SCE's 48% interest in each of Units 4 and 5 of Four Corners. A principal remaining condition to closing is the negotiation and execution of a new coal supply contract for Four Corners on terms reasonably acceptable to APS. See Coal Supply below. APS has announced that, if APS's purchase of SCE's interests in Units 4 and 5 at Four Corners is consummated, it will shut down Units 1, 2, and 3 at Four Corners. On May 9, 2013, the Arizona Corporation Commission ("ACC"), which regulates APS, voted to re-examine the facilitation of a deregulated retail electric market in Arizona. In connection with this matter, APS announced that it would not be in a position to close the Four Corners purchase transaction with SCE until the ACC's intentions with regard to pursuing deregulation in Arizona became clearer. In September 2013, the ACC closed the deregulation docket. Certain parties have filed motions for rehearing, which are pending before the ACC. Pursuant to the asset purchase agreement, because all of the closing conditions were not originally satisfied by December 31, 2012, either APS or SCE has a right to terminate the agreement,

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)

unless the party seeking to terminate is then in breach. Although the ACC closed its deregulation docket, APS has reported that it cannot predict whether the closing conditions will be satisfied such that closing of its planned purchase of SCE's interest in Four Corners can occur.

Four Corners BART FIP Challenge

On October 22, 2012, WEG filed a petition for review in the Ninth Circuit challenging the Four Corners BART FIP.  In its petition, WEG alleges that the final BART rule results in more air pollution being emitted into the air than allowed by law and that EPA failed to follow the requirements of the ESA.  APS intervened in this matter and filed a motion to dismiss this lawsuit for lack of jurisdiction or alternatively to transfer the lawsuit to the Tenth Circuit. On February 25, 2013, the Ninth Circuit denied APS' motion to dismiss, but granted the request to transfer the case to the Tenth Circuit. This matter is now proceeding in the Tenth Circuit. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

Regional Haze Challenges

On December 27, 2012, WEG filed a petition for review in the Tenth Circuit challenging the SO₂ and particulate matter emissions elements of EPA's approval of New Mexico's Regional Haze SIP.  On February 26, 2013, HEAL Utah and other environmental groups filed petitions in the Tenth Circuit challenging EPA's final approval of the remaining elements of New Mexico's Regional Haze SIP, as well as EPA's approval of the Albuquerque/Bernalillo County Air Quality Control Board SIP. PNM was granted intervention in both matters and the Tenth Circuit consolidated the two matters based on the similarity of issues. This matter is now proceeding in the Tenth Circuit. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

SJGS Operating Permit Challenge

On February 16, 2012, EPA issued its response to a WEG petition objecting to SJGS's operating permit granted by the NMED in January 2011. In its order, EPA required NMED to provide clarification on several of the matters raised by WEG.  EPA's order in this matter does not constitute a finding that the plant has violated any provision of the CAA or that it has violated any emission limits. 

In August 2012, NMED issued a response to the EPA order stating that SJGS's operating permit would be reopened to make certain modifications to the permit. NMED issued a public notice regarding proposed modifications to the SJGS operating permit on September 19, 2012 and issued a revised operating permit on November 26, 2012. The revised permit includes changes to the SO₂ and particulate matter emission limits that were previously incorporated into the SJGS NSR permit. In addition, the revised permit requires PNM to submit a compliance plan to address carbon monoxide ("CO") emissions increases at SJGS Unit 2. PNM submitted a compliance plan in May 2013 and considers this matter resolved.

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. EPA has issued draft guidance on how to determine whether areas in a state comply with the new 1-hour SO₂ NAAQS. On May 21, 2013, EPA released draft guidance on characterizing air quality in areas with limited or no monitoring data near existing SO₂ sources. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO₂ NAAQS.  Although the determination process has not been finalized, PNM believes that compliance with the 1-hour SO₂ standard may require operational changes and/or equipment modifications at SJGS. On June 4, 2013, Sierra Club and National Resource Defense Council issued a NOI to sue EPA for failure to issue non-attainment designations for areas they claim to be in violation of the 2010 1-hour SO₂ standard. On April 6, 2012, PNM filed an application for an amendment to its air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. In addition, this application included a proposal by PNM to install equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO₂, and particulate matter. These modifications would help SJGS meet the NAAQS. It is anticipated that this technology would be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities at

52

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

SJGS. The cost of this technology is dependent upon the type of control technology that is ultimately determined to be NOx BART at SJGS. See Regional Haze - SJGS above.

EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications discussed above will assist with the plant with compliance 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 0.060-0.070 parts per million. EPA is reviewing its 2008 standard and is scheduled to propose a new standard in December 2013 and finalize it by the end of 2014.  Depending upon where the standard for ozone is set, San Juan County, where SJGS is situated, could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. As a result, SJGS could be required to install further NOx controls to meet a new ozone NAAQS. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional NOx controls would be required as a result of ozone non-attainment designation.

Citizen Suit Under the Clean Air Act

The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS's emissions performance. In May 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties' dispute is deemed settled.

In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM's mercury controls. NMED and plaintiffs seek to require PNM to implement additional mercury controls. PNM estimates the implementation would increase annual mercury control costs for the entire station, which are currently $0.6 million, to a total of $6.1 million. The court appointed a special master to evaluate the technical arguments in the case and to address the detection and determination limits of the mercury monitors at SJGS and the appropriate brominated activated carbon injection rate that maximizes the reduction of mercury emissions from SJGS.  The special master issued a report indicating he was unable to make a determination on either of these issues.  In September 2012, PNM submitted objections to certain portions of the special master report and requested an evidentiary hearing. Also in September 2012, NMED and plaintiffs filed a motion asking the court to affirm certain findings in the special master report and order PNM to conduct additional mercury testing. The parties have provided status updates to the court as required. PNM cannot predict the outcome of this matter.

Section 114 Request

In April 2009, APS received a request from EPA under Section 114 of the CAA seeking detailed information regarding projects at and operations of Four Corners. EPA has taken the position that many utilities have made physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the CAA. APS has responded to EPA's request. PNM is currently unable to predict the timing or content of EPA's response, if any, or any resulting actions.

Four Corners Clean Air Act Lawsuit

In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, the Four Corners owners may reinstate

53

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

their motions to dismiss without risk of default. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

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 National Environmental Policy Act 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 voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines, and enjoining operations at the seven mines. SJCC intervened in this matter and seeks to sever SJCC's claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

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.

Endangered Species Act

In January 2011, the Center for Biological Diversity, Diné Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit in the United States District Court for the District of Colorado against the OSM and the DOI, alleging that OSM failed to engage in mandatory ESA consultation with the United States Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners.  The lawsuit alleges that activities at the mine, including mining and the disposal of coal combustion residue, will adversely affect several endangered species and their critical habitats.  The lawsuit requested the court to vacate and remand the mining permit and enjoin all activities carried out under the permit until OSM has complied with the ESA.  Neither PNM nor APS was a party to the lawsuit. On March 14, 2012, the Court entered an order dismissing the plaintiffs' lawsuit without prejudice. On May 14, 2012, the plaintiffs appealed the Court's order to the Tenth Circuit. On July 8, 2013, the Tenth Circuit entered an order dismissing the appeal, which concludes this matter.

Cooling Water Intake Structures

EPA issued its proposed cooling water intake structures rule in April 2011, which would provide 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 proposed rule would require facilities such as Four Corners and SJGS to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity and to take certain protective measures with respect to impinged fish. The proposed rule would also require these facilities to either meet the definition of a closed cycle recirculating cooling system or conduct a "structured site-specific analysis" to determine what site-specific controls, if any, should be required.

54

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 proposed rule would require existing facilities to comply with the impingement mortality requirements as soon as possible, but no later than eight years after the effective date of the rule, and to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. EPA was required to issue a final rule by June 27, 2013; however, that date has been extended to November 4, 2013. PNM and APS continue to follow the rulemaking and are performing analyses to determine the potential costs of compliance with the proposed rule. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance.

Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for steam electric power plants.  EPA's proposal offers 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 wastes operations.  EPA is subject to a consent decree deadline to finalize the revised guidelines by May 22, 2014. PNM is in the process of reviewing the proposed rule to assess the impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. APS is currently assessing the impact to Four Corners. PNM is unable to predict the outcome of this matter or if it will have a material impact on PNM's financial position, results of operations, or cash flows. 

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 the 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 municipal well continues to operate and meets federal drinking water standards. The City of Santa Fe has recently 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 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 also states that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM's obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced similar results. PNM is unable to predict the outcome of this matter and does not believe the former generating station is the source of the nitrates or the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made.

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. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production.  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 includes two options for waste designation of coal ash. One option is 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 is 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

55

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)

authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA's proposal does not address the placement of CCBs in surface mine pits for reclamation. An OSM CCB rulemaking team has been formed to develop a proposed rule. 

On April 5, 2012, several environmental groups, including Sierra Club, filed a citizen suit in the D.C. Circuit claiming that EPA has failed to review and revise RCRA's regulations with respect to CCBs. The groups allege that EPA has already determined that revisions to the CCBs regulations are necessary. They also claim that EPA now has a non-discretionary duty to revise the regulations. The environmental groups asked the court to direct EPA to complete its review of the regulation of CCBs and a hazardous waste analytical procedure and to issue necessary revisions of such regulations as soon as possible. Two industry group members subsequently filed separate lawsuits in the D.C. Circuit seeking to ensure that disposal of coal ash would not be regulated as a hazardous waste. The environmental and industry lawsuits have been consolidated.

PNM advocates for the non-hazardous regulation of CCBs. However, if CCBs are ultimately regulated as a hazardous waste, costs could increase significantly. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of EPA's or OSM's proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material impact on its operations, financial position, or cash flows. 

Hazardous Air Pollutants ("HAPs") Rulemaking

In December 2011, the EPA issued its final Mercury and Air Toxics Standards ("MATS") to reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel, as well as acid gases, including hydrochloric and hydrofluoric gases, from coal and oil-fired electric generating units with a capacity of at least 25 MW. Existing facilities will generally have up to four years to demonstrate compliance with the new rule. PNM's assessment of MATS indicates that the control equipment currently used at SJGS allows the plant to meet the emission standards set forth in the rule although the plant may be required to install additional monitoring equipment. With regard to mercury, stack testing performed for EPA during the MATS rulemaking process showed that SJGS achieved a mercury removal rate of 99% or greater. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule. 

Other Commitments and Contingencies

Coal Supply

The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At September 30, 2013 and December 31, 2012, prepayments for coal, which are included in other current assets, amounted to $15.8 million and $9.9 million. These amounts reflect delivery of a portion of the prepaid coal and its utilization due to the mine fire incident described below. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement to supply processed coal for operation of SJGS through 2017. Under the coal sales agreement, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.

APS purchases all of Four Corners' coal requirements from a supplier that is also a subsidiary of BHP and has a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through July 6, 2016 with pricing determined using an escalating base-price. In December 2012, BHP announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which the coal mine would be sold to the Navajo Nation. The BHP subsidiary would be retained as the mine manager and operator until July 2016. Key terms of the new coal supply contract are being finalized by the Navajo Nation and the Four Corners owners. The Four Corners owners must finalize their approvals of the contract. These negotiations, and the related transaction whereby full ownership of the coal mine would be transferred to the Navajo Nation, are proceeding. On April 29, 2013, the Navajo Nation Tribal Council approved the creation of the new commercial enterprise with sufficient power and authority to execute the transaction with BHP. See The Clean Air Act - Regional Haze - Four Corners above. PNM is unable to predict the outcome of this matter.

56

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)

In 2010, 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. The estimate for decommissioning the Four Corners mine was also revised in 2010. Based on the 2010 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $56.9 million for the surface mines at both SJGS and Four Corners and $19.7 million for the underground mine at SJGS as of September 30, 2013. At September 30, 2013 and December 31, 2012, liabilities, in current dollars, of $23.7 million and $26.8 million for surface mine reclamation and $4.6 million and $4.2 million for underground mine reclamation were recorded in other deferred credits.

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 ratepayers 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. In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA discussed under The Clean Air Act - Regional Haze - SJGS above, an updated coal mine reclamation study was requested by the SJGS participants. 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. Although the updated coal mine reclamation study has not been finalized, preliminary indications are that reclamation costs for both the surface and underground mines have increased, including significant increases due to the shutdown of SJGS Units 2 and 3. The shutdown of Units 2 and 3 would reduce the amount of CCBs generated over the remaining life of SJGS, which could result in a significant increase in the amount of fill dirt required to remediate the surface mine pits thereby increasing the overall reclamation costs. The amount of any increase and the allocation between the surface and underground mines cannot be determined at this time. Furthermore, it has not been decided how costs would be divided among the owners of SJGS, which may be dependent on the final decision regarding how SJGS ownership is restructured. 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 impact.

San Juan Underground Mine Fire Incident

On September 9, 2011, a fire was discovered at the underground mine owned and operated by SJCC that provides coal for SJGS. The federal Mine Safety and Health Administration ("MSHA") was notified of the incident. On September 12, 2011, SJCC informed PNM that the fire was extinguished. However, MSHA required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. SJCC regained entry into the sealed area of the mine in early March 2012. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. If further difficulties occur in the longwall mining operation, PNM and the other owners of SJGS would need to consider alternatives for operating SJGS, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time.

The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM anticipates that it will recover through its FPPAC the portion of such costs allocable to its customers subject to New Mexico regulation. PNM's filings with the NMPRC reflect an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by $21.6 million. SJCC submitted an insurance claim regarding the costs it incurred due to the mine fire and has informed PNM that it has settled with its insurance carrier. PNM believes the settlement proceeds obtained by SJCC through its insurance carrier are reimbursable (in whole or in part) to the owners of SJGS through the coal sales agreement. PNM's portion of the insurance recovery, which is estimated to be $18.7 million based on information received from SJCC, will be flowed through PNM's FPPAC to the extent it relates to increased coal costs included in the FPPAC.

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.

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

57

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 the application of the underground royalty rate to CHM.  In August 2006, SJCC and MMS entered into a settlement agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal.  The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed.  PNM's share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM's FPPAC. PNM is unable to predict the outcome of this matter.

SJCC Arbitration

The coal supply agreement for SJGS provides that the participants in SJGS have the right to audit the costs billed by SJCC. An independent accounting firm has been engaged to perform audits of the costs billed under the provisions of the contract. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC. As provided in the contract, certain issues have been submitted to a panel for binding arbitration. In October 2013, the arbitration panel ruled on one issue and set other issues for hearing. The panel ruled that the SJGS participants owe SJCC $1.5 million for disputed mining costs.  PNM's share of this amount is $0.7 million of which $0.5 million will be passed through PNM's FPPAC. The remaining issues going forward to a hearing include: 1) whether the SJGS participants owe SJCC unbilled mining costsof $5.2 million or whether SJCC owes the SJGS participants overbilled mining costs of $1.1 million, and 2) whether SJCC billed the SJGS participants $12.9 million as mining costs that SJCC should have considered to be capital improvements, which are not billable under the mining contract.  PNM's share of any amounts resulting from the arbitration would be approximately 46.3%. Of PNM's share of the costs, approximately 33% of the first remaining issue as well as approximately 25% of the second remaining issue would be passed through PNM's FPPAC and the rest would impact earnings. A hearing date on the remaining issues has not been set. PNM is unable to predict the outcome of the arbitration hearing.

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. PNM's share of any amounts paid related to this assessment would be approximately 8%, all of which would be passed through PNM's FPPAC. 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. The NMTRD denied the refund claim. Prior to year end, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, intend to file a complaint with the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. PNM believes the assessment and the refund claim denial are without merit, but cannot predict the outcome of this matter.

Nuclear Fuel

In late August 2012, one of PVNGS's suppliers that converts uranium concentrates to uranium hexafluoride invoked the force majeure provision in its contract when it shut down its conversion plant due to regulatory compliance issues. The issues have been resolved and the conversion plant has restarted. The PVNGS participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The PVNGS participants have sufficient strategic reserves of enriched uranium such that they do not anticipate a short-term impact on nuclear fuel supplies as a result of the force majeure declaration.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson 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 the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.6 billion per occurrence. Commercial insurance carriers provide $375 million and $13.2 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 assessment per incident for all three units is $38.9 million, with an annual payment limitation of $5.7 million.

58

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 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"). Effective April 1, 2013, a sublimit of $1.5 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 assessments of $4.3 million for each retrospective assessment declared by NEIL's Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions 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. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Delta, Afton, Luna, and Lordsburg. Water availability does not appear to be 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 allocations could pose a threat of reduced water availability for these plants.

PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines to accommodate the possibility of inadequate precipitation in coming years. Since 2004, PNM has entered into agreements for voluntary sharing of the impacts of water shortages with tribes and other water users in the San Juan basin. This agreement has been extended through 2016. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement with the Jicarilla Apache Nation on a supplemental contract relating to water for SJGS and Four Corners that runs through 2016. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather or its ramifications, or how policy, regulations, and legislation may impact PNM should water shortages occur in the future.

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 has ordered that settlement of the Navajo Nation's claims under the settlement agreement and entry of the proposed decrees be heard in an expedited proceeding.  The court recently issued an order finding that no evidentiary hearing is warranted in the Navajo Nation proceeding, and that it will be issuing an order addressing the issues raised by the parties at some point in the future. This order must be entered no later than December 31, 2013, pursuant to the 2005 settlement.

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. Therefore, PNM has elected to participate in this proceeding.  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.

59

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 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.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS' fuel cost adjustment clause practices and issues relating to demand cost allocation (the "Golden Spread Proceeding"). In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM ("SPS 2006 Rate Proceeding"). In 2008, FERC issued its order in the Golden Spread Proceeding affirming an ALJ decision that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues that had been ordered by the ALJ.  FERC also reversed the decision of the ALJ, which had been favorable to PNM, on the demand cost allocation issues. PNM and SPS filed petitions for rehearing and clarification of the scope of the remedies that were ordered and seeking reversal of various rulings in the order. On August 15, 2013, FERC issued separate orders in the Golden Spread Proceeding and in the SPS 2006 Rate Proceeding. The order in the Golden Spread Proceeding determined that PNM was not entitled to refunds for SPS' fuel cost adjustment clause practices. That order and the order in the SPS 2006 Rate Proceeding decided the demand cost allocation issues using the method that PNM had advocated.  PNM, SPS, and other customers of SPS have filed requests for rehearing of these orders and they are pending further action by FERC. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes.

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.  PNM continues to participate in this matter in order to preserve its interests regarding any PNM-acquired rights-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time.

In a separate matter, in September 2012, forty-three 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. PNM is participating in this matter in order to preserve its interests regarding the right-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time.

TGP Complaint

On March 2, 2012, TGP Granada, LLC and its affiliate (collectively, "TGP") filed a complaint at FERC against PNM and Tortoise Capital Resources Corp. ("TTO"). PNM owns 60% of the EIP and leases the other 40% from TTO. PNM's lease of the portion of the EIP owned by TTO expires on April 1, 2015. The lease provides PNM the option, with 24 months advance notice, of purchasing the leased assets at the end of the lease for fair market value, as well as options to renew the lease.

TGP's filing requested FERC to direct PNM and TTO to identify the party that will immediately assume the obligation of making transmission capacity on the EIP available to customers for use after the April 1, 2015 expiration of the EIP lease agreement. TGP also requested a declaratory order or waiver regarding certain provisions of PNM's Open Access Transmission Tariff to allow its affiliate to change the point-of-receipt associated with a transmission service agreement related to the EIP without losing its

60

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)

transmission service priority. On July 5, 2012, FERC issued an order denying TGP's requests for declaratory order and waiver. In addition, FERC directed PNM, in consultation with TTO, to identify the party that will provide long-term transmission service over the leased portion of the EIP.

On November 1, 2012, PNM and TTO entered into a definitive agreement for PNM to exercise the option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. The lease remains in existence and PNM will record the purchase at the termination of the lease on April 1, 2015. The definitive agreement sets forth the terms and conditions under which PNM would also assume responsibility for scheduling long-term transmission service on the leased capacity. In November 2012, PNM requested the necessary FERC approvals for the definitive agreement. In January 2013, FERC approved PNM's requests. On February 8, 2013, FERC issued an order dismissing as moot a motion filed by TGP for clarification of FERC's July 5, 2012 order. Since no rehearing request or appeal was filed, the February 8, 2013 order is final and non-appealable.

(11) 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 10. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

PNM

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. The NMPRC requires renewable energy portfolios to be "fully diversified." Prior to December 2012, the diversity requirements were 20% from wind energy, 20% from solar energy, 10% from other renewable technologies, and 1.5% from distributed generation with the distributed generation component increasing to 3% in 2015. In December 2012, NMPRC issued an order that amended the diversity requirements to 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015, and adopted other changes to its renewable energy rule, including the increase in the RCT discussed below. In June 2013, the NMPRC initiated a new rulemaking proceeding in which it proposed to consider amending or eliminating specific diversity targets and to reconsider the inclusion of avoided environmental and capacity costs in the application of the RCT. A public hearing was held on September 10, 2013.

The REA provides for streamlined proceedings for approval of utilities' renewable energy procurement plans, assures utilities that they 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. The NMPRC had established a RCT for 2011 of 2% of all customers' aggregated overall annual electric charges that increased by 0.25% annually until reaching 3% in 2015. In December 2012, the NMPRC approved an amended RCT set at 3% of customers' annual electric charges beginning in 2013 and continuing thereafter.

In July 2011, PNM filed its renewable energy procurement plan for 2012. The plan requested a variance from the RPS due to RCT limitations. The plan was diversity-compliant based on the reduced RPS, except for non-wind/non-solar resources, which were not available. In December 2011, the NMPRC approved PNM's 2012 plan, but ordered PNM to spend an additional $0.9 million on renewable procurements in 2012. PNM is recovering the costs of the supplemental procurements through the renewable rider discussed below. The NMPRC also required PNM to file its 2013 renewable energy procurement plan by April 30, 2012. The 2013 plan proposed procurements for 2013 and 2014 of 20 MW of PNM-owned solar PV facilities, at an estimated cost of $45.5 million, wind and solar REC purchases in 2013, and a PPA for the output of a new 10 MW geothermal facility. The plan also included an additional procurement of 2 MW of PNM-owned solar PV facilities at an estimated cost of $4.5 million to supply the energy sold under PNM's voluntary renewable energy tariff. The plan will enable PNM to comply with the statutory RPS amount in 2013, but requires a variance from the NMPRC's diversity requirements in 2013 while the proposed geothermal facilities are being constructed. This plan had been expected to achieve full RPS quantity and diversity compliance by 2014 without exceeding the RCT. The NMPRC approved the plan in December 2012, but reduced the additional solar PV procurement from 2 MW to 1.5 MW. Construction of the geothermal facility has been delayed due to a longer than expected permitting process. PNM

61

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)

still anticipates that the facility will begin energy production January 1, 2014, but full-scale production will be delayed. PNM does not believe this delay will affect its ability to comply with the diversity requirements as amended in December 2012.

PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets the RPS quantity and diversity requirements within the RCT in 2014 and 2015. PNM's proposed procurements include 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of an existing 100 MW wind energy center beginning January 1, 2015 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015. A public hearing was held in October 2013. The NMPRC is required to approve or modify the plan within 180 days of the filing date. PNM cannot predict the outcome of this proceeding.

PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Riderbelow.

Renewable Energy Rider

On August 14, 2012, the NMPRC authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The approved rates are $0.0022335 per KWh in 2012 and $0.0028371 per KWh in 2013. The order disapproved the recovery of the cost of a supplemental REC procurement ordered by the NMPRC in the 2012 procurement plan case because the NMPRC had not yet acted on the specific $0.9 million procurement proposed by PNM, which is discussed under Renewable Portfolio Standard above. The NMPRC subsequently approved the supplemental REC procurement, but ordered that a hearing be held on its inclusion in the rider. Upon NMPRC approval, PNM implemented the rider on August 20, 2012. The rider will terminate upon a final order in PNM's next general rate case unless the NMPRC authorizes PNM to continue it. Amounts collected under the rider are capped at $18.0 million in 2012 and $24.6 million in 2013. Any amounts above the caps are deferred for future recovery without carrying costs. As a separate component of the rider, if PNM's earned return on jurisdictional equity in 2013, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM must refund to customers during May through December 2014 the amount over 10.5%.

In compliance with the NMPRC's rate rider order, PNM filed a notice to implement an increase in the current rider rate effective with May 2013 bills.  The NMPRC suspended the effective date of the new rate for a period of nine months from April 1, 2013 and appointed a Hearing Examiner to conduct a hearing on the proposed change.  On May 15, 2013, the NMPRC approved the requested increase. PNM implemented the new rate of $0.0030468 per KWh on May 28, 2013.

In its 2014 renewable energy procurement plan described above, PNM proposed to increase the rider rate to $0.0044391 effective January 1, 2014. PNM expects an order in this case in December 2013.

Energy Efficiency and Load Management

Program Costs

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

In October 2012, PNM filed an energy efficiency program application for programs to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive of $4.2 million and requested that the NMPRC issue an order by April 1, 2013. Portions of the program plan and proposed profit incentive are opposed by other parties to the case. PNM subsequently revised its proposed profit incentive to $2.9 million. After a hearing held in February 2013, the Hearing Examiner recommended approval of the programs as proposed and recommended an annual incentive of $1.7 million. The NMPRC has not yet acted on the Hearing Examiner's recommendations. PNM is not able to predict the outcome of this matter.

62

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)

Disincentives/Incentives Adder

The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. A rule approved by the NMPRC authorized electric utilities to collect rate adders of $0.01 per KWh for lifetime energy savings and $10 per KW for demand savings related to energy efficiency and demand response programs beginning in 2010. The NMAG and NMIEC appealed the NMPRC order adopting this rule to the New Mexico Supreme Court. PNM began implementing a rate rider under the rule to collect adders related to its 2010 program savings in December 2010 while the appeal of the rule was pending. In July 2011, the Supreme Court annulled and vacated the order adopting the rule and remanded the matter to the NMPRC. As a result of the Supreme Court decision, PNM filed revised tariffs and ceased collecting this adder for 2010 program savings on August 21, 2011. Of the $4.2 million authorized for recovery, $2.6 million was collected through August 20, 2011.

In June 2011, prior to the Supreme Court decision, the NMPRC approved PNM-specific adders of $0.002 per KWh and $4 per KW for savings due to programs implemented in 2011. PNM is presently collecting $1.3 million in adder revenues consistent with this order. After the Supreme Court decision vacating the rule, the NMPRC initiated a proceeding to determine whether PNM should be required to cease collecting the adders and to refund all adder revenues collected since December 2010. In November 2011, the NMPRC issued orders that PNM is not required to refund any adder revenues and is authorized to continue collecting the adders. However, in an order on rehearing, which it subsequently rescinded, the NMPRC further reduced the amount of the authorized adders. Prior to the rescission, PNM appealed the rehearing order to the Supreme Court. In March 2012, the Supreme Court granted PNM's motion to vacate the rehearing order and dismiss PNM's appeal. In a separate appeal and writ proceeding in the Supreme Court, NMIEC and the NMAG sought to overturn the NMPRC order allowing PNM to continue to collect adders in light of the 2011 Supreme Court decision. On May 21, 2012, the Supreme Court dismissed the writ proceeding. On September 20, 2013, the Supreme Court issued a decision in the NMIEC and NMAG appeal. The Supreme Court affirmed the NMPRC's decision authorizing the incentive and remanded the case to the NMPRC. On October, 2, 2013, the NMPRC closed the docket.

On March 27, 2013, PNM filed its reconciliation for actual energy efficiency program costs, associated incentives, and actual collections for calendar year 2012. The reconciliation filing showed a net over-recovery of $0.2 million, composed of an over-recovery of $1.0 million of program costs and an under-recovery of incentives of $0.8 million. PNM subsequently revised the estimated incentive under-recovery to $0.5 million. PNM and the NMPRC staff filed a motion seeking to substitute the new reconciliation filing with a proposed effective date of May 28, 2013. On April 24, 2013, the NMPRC issued an order granting the motion. PNM implemented the new rate on May 28, 2013.

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 from the rates charged on a per KWh of consumption, as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement the New Mexico Efficient Use of Energy Act. Included in the proposed rule is a provision that would limit incentive awards to an amount equal to the product (expressed in dollars) of the utility's weighted cost of capital (expressed as a percent) and its approved annual program costs. The NOPR establishes a schedule for comments and sets a public hearing in November 2013.

2010 Electric Rate Case and FPPAC

An order of the NMPRC approving an amended stipulation in PNM's 2010 Electric Rate Case limits the amount that can be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs during certain years. Costs in excess of the limits are deferred, without carrying costs, for recovery in future periods. The fuel cost caps are $38.8 million for the FPPAC year beginning July 1, 2012, which PNM began collecting at that time, and $36.2 million for the FPPAC year beginning July 1, 2013. PNM estimates that the caps will result in approximately $38.4 million of FPPAC costs being deferred for future

63

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)

collection at June 30, 2014. The portion of the costs and insurance recovery attributable to customers covered by the FPPAC resulting from the mine fire incident discussed in Note 10 are included in the FPPAC amounts.

Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On May 28, 2013, PNM filed the required continuation application and requested that its current FPPAC be modified to increase the reset frequency of the fuel factor from annually to quarterly, to allow PNM to retain 10% of its off-system sales margin, and to apply the same carrying charge rate to either over or under-collections in the balancing account. A hearing has been scheduled to begin on December 10, 2013. PNM is unable to predict the outcome of this proceeding.

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. In its most recent IRP, which was filed in July 2011, PNM indicated that it planned to meet its anticipated load growth through a combination of new natural gas-fired generating plants, renewable energy resources, load management, and energy efficiency programs. As required by NMPRC rules, PNM utilized a public advisory group process during the development of the 2011 IRP. Two protests were filed to the IRP requesting rejection of the plan. The NMPRC assigned the case to a Hearing Examiner and designated a mediator to facilitate negotiations. The NMPRC staff filed a motion in December 2011 to dismiss the protests and terminate the proceeding on the ground that PNM's IRP fully complies with NMPRC rules. On September 18, 2013, the NMPRC issued an order that closed this docket.

Consistent with the NMPRC's IRP rule, PNM has initiated the process to prepare its 2014 IRP. Initial public participation meetings have been held. The 2014 IRP is scheduled to be filed at the NMPRC by June 30, 2014.

Emergency FPPAC

In 2008, the NMPRC authorized PNM to implement an Emergency FPPAC from June 2, 2008 through June 30, 2009. The NMPRC order approving the Emergency FPPAC also provided that if PNM's base load generating units did not operate at or above a specified capacity factor and PNM was required to obtain replacement power to serve jurisdictional customers, PNM would be required to make a filing with the NMPRC seeking approval of the replacement power costs. In its required filing, PNM stated that the costs of the replacement power amounting to $8.0 million were prudently incurred and made a motion that they be approved. The NMPRC staff opposed PNM's motion and recommended that PNM be required to refund the amount collected. Auditors selected by the NMPRC found that PNM was prudent in operating its base load units and in securing replacement power but had not obtained prior NMPRC approval in the manner required by the NMPRC order. PNM continues to assert that its recovery of replacement power costs was proper and did not violate the NMPRC's order. The NMPRC has not ruled on this matter. Under the terms of the approved stipulation in the 2010 Electric Rate Case, the parties to the stipulation, including the NMPRC staff, jointly requested that the NMPRC take no further action in this matter and close the docket. No party opposed that request. Although the NMPRC has not acted on the joint request, the NMPRC electronic docket shows the docket closed.

Applications for Approvals to Purchase Delta

As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K, PNM has entered in to an agreement to purchase Delta, a 132 MW natural gas peaking unit from which PNM currently acquires energy and capacity under a PPA. The agreement to purchase Delta required approvals by the NMPRC and FERC. On January 3, 2013, PNM filed an application with the NMPRC for a CCN to own and operate Delta and for a determination of related ratemaking principles and treatment. On June 26, 2013, the NMPRC granted PNM's CCN application and approved PNM's proposed ratemaking treatment. PNM filed an application for approval of the Delta acquisition at FERC on January 24, 2013. FERC approved the purchase on February 26, 2013. Closing on the purchase is anticipated in early 2014.

Application for Approval of La Luz Generating Station

On May 17, 2013, PNM filed an application with the NMPRC for a CCN to construct, own, and operate a 40 MW gas-fired generating facility near Belen, New Mexico. The application also requests a determination of related ratemaking principles and treatment. The facility is expected to cost approximately $63.2 million and go into service in the first quarter of 2016. PNM has entered into a contract for purchase of the turbine to be used for this project and a separate contract for the construction of the facility on a turn-key basis. Both contracts allow PNM to cancel if NMPRC approval is not obtained. A hearing on PNM's application is scheduled to begin on April 8, 2014. PNM is unable to predict the outcome of this matter.

64

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)

San Juan Generating Station Units 2 and 3 Retirement

PNM anticipates filing an application at the NMPRC to retire SJGS Units 2 and 3, as discussed in Note 10, before the end of 2013. In the same application, PNM will also seek approval to recover its remaining costs in SJGS 2 and 3 and for a CCN for some of the resources to replace the retired units, which PNM anticipates will include PNM's share of PVNGS Unit 3 and additional capacity in SJGS Unit 4. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements.

Transmission Rate Case

In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually, based on a return on equity of 12.25%. The filing also sought to revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms.  In December 2010, FERC issued an order accepting PNM's filing and suspending the proposed tariff revisions for five months. The proposed rates were implemented on June 1, 2011, subject to refund. The rate increase applied to all of PNM's wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM's transmission system to transmit power at the wholesale level.  The rate increase did not impact PNM's retail customers. On January 2, 2013, FERC approved an unopposed settlement agreement, which increases transmission service revenues by $2.9 million annually. In addition, the parties agreed that if PNM files for a formula based rate change within one year from FERC's approval of the settlement agreement, no party will oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM refunded amounts collected in excess of the settled rates in January 2013 concluding this matter.

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. The rates resulting from PNM's application are intended to replace the rates approved by the FERC on January 2, 2013 in the transmission rate case discussed above. As filed, PNM's request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM's 2011 data and a 10.81% return on equity, and authority to adjust transmission rates annually based on an approved formula. The proposed $3.2 million rate increase would be in addition to the $2.9 million rate increase approved by the FERC on January 2, 2013.

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 return-on-equity ("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. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC's order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC on January 2, 2013. The new rates will apply to all of PNM's wholesale electric transmission service customers. The new rates will not apply to PNM's retail customers. On June 10, 2013, FERC denied PNM's motion for rehearing regarding FERC's order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding.

65

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)

Tri-State Complaint

On March 13, 2013, Tri-State filed a complaint with FERC alleging that PNM's existing transmission rates approved by FERC on January 2, 2013 in the transmission rate case discussed above are unjust and unreasonable under the Federal Power Act.  Tri-State's allegations were premised upon FERC's March 1, 2013 order and certain data provided by PNM in PNM's Formula Transmission Rate Case discussed above.  Tri-State sought a reduction in PNM's annual transmission revenue requirement for the period between March 13, 2013 and the implementation of PNM's proposed rates under the Formula Transmission Rate Case.  Tri-State also requested that FERC consolidate the complaint proceeding with the Formula Transmission Rate Case.  On April 2, 2013, PNM answered Tri-State's complaint, asking FERC to dismiss the complaint and deny Tri-State's request to consolidate the complaint proceeding with the Formula Transmission Rate Case. On June 10, 2013, FERC dismissed Tri-State's complaint and denied Tri-State's request to consolidate the complaint proceeding with the PNM FERC Transmission Formula Rate Case. This matter is now concluded.

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc. Rate Case

In September 2011, PNM filed an unexecuted amended sales agreement between PNM and NEC with FERC. The agreement proposed a cost of service based rate for the electric service and ancillary services PNM provides to NEC, which would result in an annual increase of $8.7 million or a 39.8% increase over existing rates. PNM also requested a FPPAC and full recovery of certain third-party transmission charges PNM incurs to serve NEC. NEC filed a protest to PNM's filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and PNM filed for the necessary FERC approval on December 6, 2012. The settlement agreement would result in an annual increase of $5.3 million, an extension of the contract for 10 years, and an agreement that PNM will be able to file an application for formula based rates to be effective in 2015. On April 5, 2013, FERC approved the settlement agreement. PNM has refunded the amounts collected in excess of the settled rates concluding this matter.

City of Gallup, New Mexico Contract Approval Case

PNM provides both energy and power services to Gallup, PNM's second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On May 1, 2013, PNM requested FERC approval of the amended agreement to be effective July 1, 2013. On June 21, 2013, FERC approved the amended agreement. Revenue from Gallup will increase by $3.1 million during the term of the amended agreement. On September 26, 2013, Gallup issued a request for proposals for long term power supply. Proposals are due November 26, 2013. PNM anticipates submitting a proposal, but is unable to predict if services provided to Gallup will continue upon expiration of the amended agreement.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.3 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 and is scheduled to be completed over a 5-year period.

In February 2012, the PUCT opened a proceeding to consider the feasibility of an "opt-out" program for retail consumers that wish to decline receipt of an advanced meter. The PUCT has requested comments and convened a public meeting to hear various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012.

On February 21, 2013, the PUCT filed a proposed rule to permit customers to opt-out of the AMS deployment. 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 will be borne by opt-out customers

66

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)

through an initial fee and ongoing monthly charge. All transmission and distribution utilities in ERCOT are required to initiate proceedings to establish these charges.

On September 30, 2013, TNMP filed an application to set the initial fee and monthly charges to be assessed for non-standard metering service provided to those retail customers who choose to decline the advanced meter necessary for standard metering service. TNMP's filing seeks recovery of $0.2 million through proposed initial fees ranging from $142.84 to $247.48. An additional $0.5 million in ongoing expenses would be recovered via a proposed monthly charge of $38.99. As the proceeding has just been initiated, TNMP cannot predict the outcome of this proceeding although TNMP does not expect it to have a material impact on its financial position, results of operations, or cash flows.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor. On August 28, 2012, the PUCT approved a settlement that permits TNMP to collect estimated 2013 program costs of $4.8 million, plus recovery of an aggregate of $0.4 million in under-collected costs from prior years, case expenses, and a performance bonus for 2011. TNMP's new rates were effective January 1, 2013. On May 15, 2013, TNMP filed its 2014 energy efficiency cost recovery factor application with the PUCT. The application seeks approval to collect $5.6 million, which includes $4.7 million in estimated program expenses for 2014, a $0.7 million performance bonus for 2012, a refund of $0.1 million over collection of energy savings expenses for the 2012 program year, and case expenses. In July 2013, the parties filed a settlement to permit TNMP to collect the substantially all of the requested $5.6 million. The settlement was approved by the PUCT on October 25, 2013.

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.

On January 31, 2013, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base was $21.9 million, which would increase revenues $2.9 million annually. On March 19, 2013, the PUCT ALJ approved TNMP's interim transmission cost of service filing and rates went into effect with bills rendered March 20, 2013. On August 1, 2013, TNMP filed an application to further update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $18.1 million, which would increase revenues by $2.8 million annually. The PUCT ALJ approved TNMP's interim transmission cost of service filing and rates went into effect with bills rendered on September 17, 2013.

Consolidated Tax Savings Adjustment

On June 14, 2013, the Governor of Texas signed into law a bill eliminating the consolidated tax savings adjustment ("CTSA") from electric utility ratemaking in Texas. Previously, the CTSA required electric utilities to artificially reduce their respective tax expenses due to the losses incurred by their affiliates. The bill became effective on September 1, 2013.

67

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)

(12) 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,
	2013		2012		2013	2012
	(In thousands)
Services billings:
PNMR to PNM	$	22,241	$	22,143	65,729	68,030
PNMR to TNMP	6,731		6,439		20,948	20,206
PNM to TNMP	140		184		381	473
TNMP to PNMR	2		4		6	12
Interest billings:
PNMR to TNMP	139		22		354	72
PNMR to PNM	—		—		1	1
PNM to PNMR	35		45		113	134
Income tax sharing payments:
PNMR to PNM	—		—		45,000	63,114
PNMR to TNMP	—		—		—	1,952

(13) Income Taxes

As required under GAAP, the Company makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. Year-to-date income tax expense is then calculated by applying the anticipated annual effective tax rate to year-to-date earnings before taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, as well as adjustments due to enactment of new tax laws, be excluded from the estimated annual effective tax rate calculation.

On January 3, 2013, the American Taxpayer Relief Act of 2012, which extended fifty percent bonus depreciation, was signed into law.  Due to provisions in the act, taxes payable to the State of New Mexico for 2013 were reduced, which resulted in an impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR was required to record this impairment, which after federal income tax benefit, amounted to $1.5 million as additional income tax expense during the three months ended March 31, 2013. This impairment is reflected in PNMR's Corporate and Other segment.

On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction will be 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. 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. The increase in the regulatory liability was $23.9 million. The portion of the adjustment that is not related to PNM's regulated activities was recorded as a reduction in deferred tax assets and an increase in income tax expense of $1.2 million during the three months ended June 30, 2013. This additional income tax expense is reflected in PNMR's Corporate and Other segment.

The future reduction in taxes payable to the State of New Mexico resulting from the rate reduction in House Bill 641 and revisions in estimates of future taxable income resulted in a further impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR was required to record this impairment, which after federal income tax benefit, amounted to

68

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)

$2.4 million as additional income tax expense during the three months ended June 30, 2013. This impairment is reflected in PNMR's Corporate and Other segment.

On April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for electric generation property.  Adoption of the safe harbor method is elective for years ending on or after December 31, 2012.  On July 11, 2013, the IRS issued a directive that suspends most current examination activity related to generation repairs methodology for any company that is eligible for the safe harbor. PNM is evaluating the possible effects of adopting the safe harbor method and the ultimate outcome cannot be determined at this time although the effects are not expected to be material.

In May 2013, PNMR received a refund of federal income taxes paid in prior years, which primarily was due to bonus tax depreciation and changes in the Company's method of accounting for repairs expense for income tax purposes. The total refund was $96.2 million of which $77.4 million was attributable to PNM. As of September 30, 2013, $45.0 million had been transferred to PNM.

On September 13, 2013, the IRS issued final regulations addressing the recovery of amounts paid to acquire, produce, or improve tangible personal property and the accounting for and retirement of depreciable property. Also issued were proposed regulations addressing dispositions of property. Repairs of electric transmission and distribution property and repairs of electric generation property are specifically addressed in other Revenue Procedures issued by the IRS. The effects of the remainder of regulations are being evaluated by the Company and cannot be determined at this time. However, due to PNMR's net operating loss carryforward position for income tax purposes, the effects are not expected to be material.

(14) Goodwill

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its June 6, 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 in 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

69

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)

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 the annual evaluation performed as of April 1, 2013, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit. For the PNM reporting unit, 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, 2013 and 2012 did not indicate impairments of the goodwill of any of PNMR's reporting units. The April 1, 2013 and 2012 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by more than 10%. The April 1, 2012 quantitative evaluation indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by more than 10%. Since the April 1, 2013 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 22 of Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

(15) Sale of First Choice

On September 23, 2011, PNMR entered into an agreement for the sale of First Choice to Direct LP, Inc. for $270.0 million, subject to adjustment to reflect the amounts of certain components of working capital at closing. Closing occurred on November 1, 2011. For accounting purposes, the sale was effective as of the close of business on October 31, 2011. PNMR and the purchaser disagreed about the calculation of working capital at October 31, 2011. In accordance with the agreement for the sale, this matter was submitted to an independent party for a decision binding on the parties. A decision was received in August 2012. The decision resulted in PNMR being awarded $6.4 million of the $8.2 million in dispute. PNMR recorded an additional pre-tax gain of $1.0 million, which is included in other income in the three months ended September 30, 2012.

70

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 744,000 residential, commercial, and industrial customers and end-users of electricity in New Mexico and Texas.

Strategic Goals

PNMR is focused on achieving the following strategic goals:

• Earning authorized returns on its regulated businesses

• Continuing to improve credit ratings

• Providing a top-quartile total return to investors

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

• Achieving industry-leading safety performance and customer satisfaction

• Maintaining strong plant performance and reliability

Earning Authorized Returns on Regulated Businesses

PNMR's success in accomplishing its strategic goals is highly dependent on continued favorable regulatory treatment for its utilities. The Company has multiple strategies to achieve favorable regulatory treatment, all of which have as their foundation a focus on the basics: managing the Company's business and serving customers well, 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. 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 and allow for more timely recovery of amounts invested in TNMP's systems. In 2011 and 2012, PNM made significant progress toward the goal of achieving authorized returns for its retail customers. In 2012, PNM saw additional progress toward achieving authorized returns for its transmission and generation customers regulated by FERC. PNM and TNMP completed several rate proceedings before their state regulators in 2011, 2012, and early 2013. PNM currently has a pending case before FERC in which it is requesting an increase in rates charged to transmission customers based on a formula rate mechanism. Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K and in Note 11.

Fair and timely rate treatment from regulators is crucial to achieving PNMR's strategic goals because it leads to PNM and TNMP earning their allowed returns. PNMR believes that if the utilities earn their allowed returns, it would be viewed positively by rating agencies and would further improve credit ratings, which could lower costs to customers. Also, earning allowed returns should result in increased earnings for PNMR, which should lead to increased total returns to investors.

PNM's interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates. While PVNGS Unit 3's financial contribution is not calculated in the authorized returns on its regulated business, it impacts PNM's earnings and has demonstrated to be a valuable asset. Power generated from PNM's 134 MW interest in PVNGS Unit 3 is currently sold into the wholesale market

71

and any earnings or losses are attributable to shareholders. PNM may request NMPRC approval to include PVNGS Unit 3 in the calculation of rates charged to customers in New Mexico as part of compliance with the requirements for BART at SJGS discussed below.

Continuing to Improve Credit Ratings

PNM is committed to maintaining investment grade credit ratings. The credit ratings for PNMR, PNM, and TNMP were set forth under the heading Liquidity in the MD&A contained in the 2012 Annual Reports on Form 10-K. As discussed under the subheading Liquidity in MD&A - Liquidity and Capital Resources below, S&P raised the corporate credit ratings and senior debt ratings for PNMR, PNM, and TNMP, as well as the preferred stock rating for PNM, on April 5, 2013. S&P retained the outlook as stable for all entities. On June 21, 2013, Moody's changed the ratings outlook for PNMR, PNM, and TNMP to positive from stable.

Providing Top-Quartile Total Returns to Investors

PNMR's strategic goal to provide top quartile total return to investors over the 2012 to 2016 period is based on five-year ongoing earnings per share growth plus five-year average dividend yield from a group of regulated electric utility companies with similar market capitalization. Top quartile total return currently is equal to an average annual rate of 10 percent to 13 percent. PNMR's long-term target is a dividend payout ratio of 50 percent to 60 percent of its ongoing earnings. Ongoing earnings, which is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP. The annual common stock dividend was raised by 16 percent in February 2012 and by 14 percent in February 2013. PNMR expects to provide above-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target. The PNMR board will continue to evaluate the dividend on an annual basis, considering sustainability and growth, capital planning, and industry standards.

Business Focus

In addition to its strategic goals, PNMR's strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power to create enduring value for customers and communities. To accomplish this, 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.

Reliable and Affordable Power

PNMR and its utilities are keenly aware of the roles they play in enhancing economic vitality in their New Mexico and Texas service territories. Management believes there is a direct connection between electric infrastructure to ensure reliability and economic growth. When considering expanding or relocating to other communities, businesses consider energy affordability and energy reliability to be important factors. PNM and TNMP strive to balance service affordability with infrastructure investment to maintain a high level of electric reliability. The utilities also work to ensure that rates reflect actual costs of providing service.

Investing in PNM's and TNMP's infrastructure is critical to ensure reliability and meet future energy needs. Both utilities have long-established records of providing customers with top-tier electric reliability. In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through September 30, 2013, TNMP had completed installation of more than 120,000 smart meters. TNMP's deployment is expected to be completed in 2016.

As part of the State of Texas' long-term initiative to create a smart electric grid, the smart meter rollout will ultimately give consumers more energy consumption data and help them make more informed decisions. In 2014, TNMP will install a new outage management system that will leverage capabilities of the smart meters to enhance TNMP's responsiveness to outages.

During the 2010 to 2012 period, PNM and TNMP together invested $803.7 million in substations, power plants, and transmission and distribution systems in New Mexico and Texas. In 2012, PNM announced its planned 40 MW natural gas-fired La Luz peaking generating station to be located near Belen, New Mexico. PNM filed a request in May 2013 with the NMPRC for approval for construction of the La Luz project, which is expected to begin in 2014, with the facility going into service in 2016. PNM also announced an agreement to purchase Delta, a 132 MW gas-fired peaking facility, which has served PNM jurisdictional needs under a 20-year PPA since 2000. The purchase has been approved by the NMPRC and FERC. Closing on the purchase is anticipated in early 2014.

72

Environmentally Responsible Power

PNMR has a long-standing record of environmental stewardship. In 2012 and 2013, its environmental focus has been in three key areas:

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

• Developing strategies to meet regional haze rules at the coal-fired SJGS as cost effectively as possible while providing broad environmental benefits

•Increasing energy efficiency participation

Another area of emphasis is the reduction of the amount of fresh water used during the generation of power at PNM's power plants. The fresh water used per MWh generated has dropped by 22.3% since 2002, primarily due to the growth of renewable energy sources, the expansion of Afton to a combined-cycle plant that has both air and water cooling systems, and the use of gray water for cooling at Luna. In addition to the above areas of focus, in 2013, the Company also will be working to reduce the amount of solid waste going to landfills through increased recycling and reduction of waste. The Company has performed well in this area in the past and has set goals for even further reductions.

Renewable Energy

In 2012, PNM filed and the NMPRC approved PNM's 2013 renewable procurement strategy. The approved strategy will almost double PNM's existing solar capacity with the addition of 21.5 MW of utility-owned solar capacity having an estimated cost of almost $50 million. In addition to the solar expansion, the 2013 proposal includes a 20-year agreement to purchase energy from a geothermal facility to be built near Lordsburg, New Mexico. The 10 MW facility will be the first geothermal project for the PNM system. On July 1, 2013, PNM filed its 2014 renewable procurement strategy with the NMPRC. The 2014 plan calls for the construction of an additional 23 MW of utility-owned solar capacity having an estimated cost of $46.7 million, a 20 year PPA for the output of an existing 100 MW wind energy center, and the purchase of RECs in 2014 and 2015 to meet the RPS.

In addition to PNM's utility-owned PV solar facilities, 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 features one of the largest combinations of battery storage and PV energy in the nation and involves extensive research and development of smart grid concepts with the Electric Power Research Institute, East Penn Manufacturing Co., Northern New Mexico College, Sandia National Laboratories, and the University of New Mexico. When the facility went online in September 2011, it was the nation's first solar storage facility fully integrated into a utility's power grid.

PNM's existing resource portfolio includes the purchase of 204 MW of wind power. PNM also purchases power from a customer-owned distributed solar generation program having an installed capacity of 19.8 MW at the end of 2012. Distributed generation, wind, and solar power are key means for PNM to meet the RPS established by the REA and related regulations issued by the NMPRC. These rules require a utility to achieve prescribed levels of energy sales from renewable sources within its generation mix, if that can be accomplished without exceeding the RCT cost limit set by the NMPRC, which aims to moderate the cost to consumers when utilities use more renewable resources.

PNM sought and received a waiver from the NMPRC excusing it from meeting the RPS in 2012 because the cost to achieve the full RPS would exceed the RCT. The 2013 plan will enable PNM to comply with the statutory RPS amount in 2013, but required a variance from the NMPRC's diversity requirements in 2013 while the proposed geothermal facilities are being constructed. Although this plan had been expected to enable PNM to achieve full RPS quantity and diversity compliance by 2014 without exceeding the RCT, delays in the permitting process for the geothermal facility have delayed its anticipated full-scale production in-service date to later in 2014. PNM does not believe this delay will affect its ability to comply with the diversity requirements as amended in December 2012. PNM will continue to procure renewable resources while balancing the bill impact to customers in order to meet New Mexico's escalating RPS requirements.

SJGS

PNM continues its efforts to comply with the EPA regional haze rule in a manner that minimizes the cost impact to customers while still achieving broad environmental benefits. EPA's FIP for regional haze currently in effect requires the installation of SCRs on all four units at SJGS by September 2016.

Following approval by the majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the non-

73

binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP from the State of New Mexico. PNM would also build a natural gas-fired peaking generating plant to be sited at SJGS to partially replace the capacity from the retired coal units. Additional base load generating capacity may also be required, which could come from some combination of PVNGS Unit 3, renewable resources, and/or additional gas-fired generation. Implementing this plan includes:

• PNM submitting a new BART analysis to NMED, which occurred in April 2013

• NMED submitting a revised SIP to EIB, which occurred in May 2013

• Approval of the revised SIP by EIB, which occurred on September 5, 2013

• Submission of the revised SIP to EPA, which occurred on October 18, 2013

• EPA approval of the revised SIP

• NMPRC approval of the retirement of Units 2 and 3, as well as recovery of the unrecovered investment and costs to retire those units, and plans to acquire replacement power

The term sheet setting forth the non-binding agreement projects EPA final action in late 2014. Contemporaneously with the signing of the non-binding agreement, EPA indicated in writing that if the above plan does not move forward due to circumstances outside of the control of PNM and NMED, EPA will work with the State of New Mexico and PNM to create a reasonable FIP compliance schedule to reflect the time used to develop the new state plan.

In connection with the implementation of the revised plan and the retirement of SJGS Units 2 and 3, some of the SJGS participants have expressed a desire to exit their ownership in the plant. To implement the revised plan and accommodate the participants desiring to exit, the SJGS participants are negotiating a restructuring of the ownership in SJGS, as well as addressing the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items. The negotiations could result in PNM acquiring additional ownership in SJGS Unit 4. Owners of the affected units also may seek approvals of their utility commissions or governing boards.

PNM, as the SJGS operating agent, presented the SNCR project to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. The SJPPA provides that PNM is authorized and obligated to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending resolution by the participants. PNM is evaluating its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants, but has not reached a decision on how to proceed. PNM cannot predict the outcome of this matter.

On February 25, 2013, the parties filed their status reports with the Tenth Circuit.  To demonstrate that progress has been made toward settling the Tenth Circuit litigation, information, including the non-binding agreement and its accompanying timeline, was submitted to the court. Following the parties' submission of their status reports, on February 28, 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals. Currently, proceedings for relief from the Tenth Circuit are in abeyance at PNM's request.

This revised BART plan would achieve similar visibility improvements as the installation of SCRs on all four units at SJGS. It has the added advantage of reducing other emissions beyond NOx, including SO₂, particulate matter, CO₂, and mercury, as well as reducing water usage. Detailed replacement power strategies also would be finalized. PNM believes adequate replacement power alternatives will be available to meet its generation needs and ensure reliability. PNM can provide no assurance that the requirements of this plan will be accomplished at all or within the required timeframes.

Additional information about BART at SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K and in Note 10. PNM anticipates filing for NMPRC approvals regarding BART at SJGS in late 2013 as discussed in Note 11.

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. 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 43 percent, SO₂ by 69 percent, particulate matter by 63 percent, and mercury by 99 percent.

74

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 2012, annual energy saved as a result of PNM's portfolio of energy efficiency programs was approximately 79 GWh. This is equivalent to the consumption of approximately 10,700 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 2012 resulted in energy savings totaling an estimated 12.8 GWh.

Creating Value for Customers and Communities

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.

Building off work that began in 2008, PNM has continued 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 2012, PNM hosted 23 community events throughout its service territory to assist low-income customers. Furthermore, the PNM Good Neighbor Fund provided $1.0 million of assistance with utility bills to 10,216 families in 2012.

The PNM Resources Foundation helps nonprofits become more energy efficient through Reduce Your Use grants. For 2012, the foundation awarded $0.3 million to support 55 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 a total of $1.1 million of support. In May 2013, in connection with the PNM Resources Foundation's 30^th anniversary, the foundation announced that 30 $10,000 environmental grants would be awarded in 2013. The recipients were announced in August 2013.

PNM also expanded its environmental stakeholder outreach in 2012, piloting small environmental stakeholder dialogue groups on key issues such as renewable energy and energy efficiency planning. PNM also employed proactive stakeholder outreach in two key projects - the development of the PNM's renewable energy procurement plans that involved distributed solar energy developers early in the conversation and the siting of the planned gas-fired peaking generation facility near Belen, New Mexico, which featured in-depth community involvement and education early in the planning stages of the project. In both cases highly favorable outcomes were achieved and controversial negative media coverage was virtually eliminated.

Economic Factors

In the three and nine months ended September 30, 2013, PNM experienced decreases in weather and leap-year normalized, retail load of 1.2% and 1.5% compared to 2012. However, PNM set a new all-time record for peak use on June 27, 2013 when usage reached 2,008 MW. This compares to the previous peak of 1,973 MW. New Mexico businesses are taking a longer time to recover from the economic downturn.  In particular, the Albuquerque metropolitan area continues to lag the nation in economic recovery.  Based on the current trends, PNM load could be down approximately 1% for the full year 2013 compared to 2012.  In the three and nine months ended September 30, 2013, TNMP's weather normalized and leap-year adjusted load increased 3.3% and 1.9% compared to 2012. In recent years, New Mexico and Texas have fared better than the national average in unemployment. However, New Mexico's figures may be misleading due to people dropping out of the workforce. Employment growth is a better indicator. Texas growth rates are well above the national rate and New Mexico's employment growth rate is slightly positive.

Results of Operations

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012		Change			2013		2012		Change
	(In millions, except per share amounts)
Net earnings attributable to PNMR	$	54.6	$	57.9	$	(3.3	)	$	92.9	$	96.5	$	(3.6	)
Average diluted common and common equivalent shares	80.3		80.4		(0.1		)	80.5		80.4		0.1
Net earnings attributable to PNMR per diluted share	$	0.68	$	0.72	$	(0.04	)	$	1.15	$	1.20	$	(0.05	)

75

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

	Three Months Ended			Nine Months Ended
	September 30, 2013			September 30, 2013
	(In millions)
PNM	$	(3.1	)	$	(0.1	)
TNMP	1.0			2.1
Corporate and Other	(1.2		)	(5.5		)
Net change	$	(3.3	)	$	(3.6	)

PNMR's operational results were affected by the following:

• Rate increases for PNM and TNMP - Additional information about these rate increases is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K and Note 11

• Net unrealized gains and losses on mark-to-market economic hedges for sales and fuel costs not recoverable under PNM's FPPAC

• Higher prices for sales of power from PVNGS Unit 3

• Milder weather in 2013 than 2012

• Lower retail load at PNM partially offset by higher retail load in at TNMP

• Increased income tax expense due to impairments of state tax credits and a change in state tax rate (Note 13)

• Other factors impacting results of operation for each segment are discussed under Results of Operations below

Liquidity and Capital Resources

The Company has revolving credit facilities that provide capacities for short-term borrowing and letters of credit of $300.0 million for PNMR and $400.0 million for PNM, both of which expire in October 2018. In addition, TNMP has a $75.0 million revolving credit facility, which expires in September 2018. Total availability for PNMR on a consolidated basis was $755.9 million at October 25, 2013. 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 $2,054.0 million for 2013-2017, including amounts expended through September 30, 2013. The construction expenditures include additional renewable resources anticipated to be required to meet the RPS, additional peaking resources needed to meet needs outlined in PNM's current IRP, and environmental upgrades at Four Corners. This estimate does not include any amounts related to environmental upgrades at SJGS that ultimately may be required by EPA to address regional haze or expenditures that could be required to replace capacity should environmental control at SJGS involve shutdown of one or more SJGS units (Note 10). 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 through 2017. 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

Segment Information

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

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.

76

PNM

The following table summarizes the operating results for PNM:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Change			2013			2012			Change
	(In millions)
Electric operating revenues	$	326.0		$	321.7		$	4.3		$	863.6		$	832.2		$	31.4
Cost of energy	100.2			99.2			1.0			283.7			263.0			20.7
Margin	225.8			222.5			3.3			579.9			569.2			10.7
Operating expenses	104.7			101.1			3.6			311.4			311.5			(0.1		)
Depreciation and amortization	25.9			24.4			1.5			77.8			72.0			5.8
Operating income	95.2			97.0			(1.8		)	190.8			185.7			5.1
Other income (deductions)	4.5			8.4			(3.9		)	14.8			19.1			(4.3		)
Net interest charges	(20.1		)	(19.2		)	(0.9		)	(60.0		)	(56.7		)	(3.3		)
Segment earnings before income taxes	79.6			86.1			(6.5		)	145.6			148.2			(2.6		)
Income (taxes)	(27.7		)	(31.2		)	3.5			(49.2		)	(51.9		)	2.7
Valencia non-controlling interest	(4.1		)	(4.0		)	(0.1		)	(10.9		)	(10.7		)	(0.2		)
Preferred stock dividend requirements	(0.1		)	(0.1		)	—			(0.4		)	(0.4		)	—
Segment earnings	$	47.7		$	50.8		$	(3.1	)	$	85.1		$	85.2		$	(0.1	)

The following table summarizes the significant changes to electric operating revenues, cost of energy, and margin:

	2012/2013 Change
	Three Months Ended September 30,									Nine Months Ended September 30,
	Electric									Electric
	Operating			Cost of						Operating			Cost of
	Revenues			Energy			Margin			Revenues			Energy			Margin
	(In millions)
Customer usage/load	$	(1.3	)	$	—		$	(1.3	)	$	(6.4	)	$	—		$	(6.4	)
Weather	(5.0		)	—			(5.0		)	(4.9		)	—			(4.9		)
Transmission and other	(2.5		)	(0.7		)	(1.8		)	14.9			17.0			(2.1		)
Wholesale rate increases	0.5			—			0.5			2.5			—			2.5
Energy efficiency rider	(1.4		)	—			(1.4		)	(1.7		)	—			(1.7		)
Renewable energy rider	3.8			1.6			2.2			15.0			6.3			8.7
Unregulated margin	0.9			(0.4		)	1.3			3.1			(2.5		)	5.6
Net unrealized economic hedges	9.3			0.5			8.8			8.9			(0.1		)	9.0
Net change	$	4.3		$	1.0		$	3.3		$	31.4		$	20.7		$	10.7

77

The following table shows electric operating revenues by customer class and average number of customers:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2013		2012			Change			2013		2012			Change
	(In millions, except customers)
Residential	$	122.9	$	126.1		$	(3.2	)	$	319.8	$	318.9		$	0.9
Commercial	119.1		120.4			(1.3		)	319.5		317.1			2.4
Industrial	21.2		22.6			(1.4		)	57.7		59.9			(2.2		)
Public authority	8.2		8.1			0.1			20.0		19.3			0.7
Economy service	7.8		6.8			1.0			23.9		17.7			6.2
Other retail	0.4		2.3			(1.9		)	6.2		9.5			(3.3		)
Transmission	10.5		10.8			(0.3		)	28.5		29.3			(0.8		)
Firm-requirements wholesale	10.1		10.5			(0.4		)	31.0		28.8			2.2
Other sales for resale	18.2		15.8			2.4			52.0		35.4			16.6
Mark-to-market activity	7.6		(1.7		)	9.3			5.0		(3.7		)	8.7
	$	326.0	$	321.7		$	4.3		$	863.6	$	832.2		$	31.4
Average retail customers (thousands)	508.3		505.6			2.7			507.8		505.3			2.5

The following table shows GWh sales by customer class:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013	2012	Change		2013	2012	Change
	(Gigawatt hours)
Residential	955.8	975.7	(19.9	)	2,543.0	2,573.3	(30.3	)
Commercial	1,049.8	1,103.5	(53.7	)	3,001.8	3,064.1	(62.3	)
Industrial	272.2	300.3	(28.1	)	798.8	858.4	(59.6	)
Public authority	78.4	84.0	(5.6	)	205.0	211.1	(6.1	)
Economy service	174.9	171.3	3.6		528.6	454.6	74.0
Firm-requirements wholesale	157.6	162.0	(4.4	)	484.8	485.8	(1.0	)
Other sales for resale	564.2	536.9	27.3		1,592.4	1,263.4	329.0
	3,252.9	3,333.7	(80.8	)	9,154.4	8,910.7	243.7

For the three and nine months ended September 30, 2013, retail sales were lower compared to 2012 reflecting a continued sluggish economy in New Mexico. In particular, the Albuquerque metropolitan area continues to lag the nation in economic recovery. In spite of the economic pressures, PNM experienced year to date growth in average retail customers of 0.5%. Weather negatively impacted revenues and margin during the three and nine months ended September 30, 2013. Cooling degree days were 10.1% and 9.8% lower for the three and nine months ended September 30, 2013 compared to the same period in 2012. PNM's weather normalized and leap-year adjusted retail sales were lower in 2013 than in 2012 by 1.9% in the first quarter, 1.4% in the second quarter, 1.2% in the third quarter, and 1.5% for the nine months ended September 30. However, total KWh sales, excluding normalization, decreased 4.4% and 2.4% for the three and nine months ended September 30, 2013 compared to 2012. Based on the current trends, retail KWh sales could be down approximately 1% for the full year 2013 compared to 2012 on a weather normalized and leap-year adjusted basis.

PNM provides economy energy services to a major customer. In spite of the increase in KWh sales to this customer for the three and nine months ended September 30, 2013 compared to 2012, there is only a minor impact in margin resulting from providing ancillary services. Other changes in revenues and cost of energy are a pass through with no impact to margin. Other sales for resale revenues and volumes increased for the three months and nine months ended September 30, 2013, primarily due to reduced off-system sales at SJGS in 2012 resulting from the fire incident at the mine providing coal to SJGS and additional energy available for off-system sales in 2013 due to the reduction in retail load. Increased off-system sales from SJGS are included in PNM's FPPAC and do not impact margin. See Note 10 for more discussion on the SJGS mine fire incident.

78

Higher energy imbalance volumes related to contracts that are settled through an exchange of power rather than cash combined with lower transmission revenues due to expiration of contracts resulted in a decrease in margin of $1.8 million and $2.1 million in the three and nine months ended September 30, 2013 compared to 2012. Increases in rates charged to wholesale firm-requirements customers (Note 11) increased revenue and margin by $0.5 million and $2.5 million for the three and nine months ended September 30, 2013 compared to 2012.

PNM offers several energy efficiency programs and initiatives to its retail customers regulated by the NMPRC. In addition, PNM is allowed to earn incentives on these programs, based on energy savings of the programs. PNM recovers these energy efficiency program costs and incentives via a rate rider. For the three months and nine months ended September 30, 2013, revenues and margin from the energy efficiency rider were lower by $1.4 million and $1.7 million, primarily driven by lower energy efficiency billings, which were partly offset by additional incentives earned in 2013 compared to those earned in 2012. Changes in energy efficiency revenues are offset by changes in operating expenses.

In August 2012, PNM implemented its renewable energy rider, a mechanism approved by the NMPRC, which recovers renewable energy procurement costs, including the investment in and an allowed return on the 22 MW of PNM-owned solar PV facilities constructed to meet the RPS. See Note 11. For the three months and nine months ended September 30, 2013, this rider increased revenues by $3.8 million and $15.0 million and cost of energy, reflecting the purchase of RECs, by $1.6 million and $6.3 million. These revenues include a return on investment of $0.9 million and $2.8 million for the three and nine months ended September 30, 2013 compared to $0.3 million for the three and nine months ended September 30, 2012. The remaining revenues from this rider recover renewable energy operating, depreciation, and interest expenses.

For the three months and nine months ended September 30, 2013, higher unregulated revenues of $0.9 million and $3.1 million and margin of $1.3 million and $5.6 million, primarily associated with PNM's share of PVNGS Unit 3, were due to higher market power prices on sales compared to 2012. In addition, PNM incurred an expense of $2.0 million for gas imbalance settlements in the three months ended September 30, 2012 that did not recur in 2013.

Changes in unrealized mark-to-market gains and losses are based on economic hedges in place for sales and fuel costs not covered under the FPPAC, primarily associated with PVNGS Unit 3. Unrealized gains of $7.7 million for the three months ended September 30, 2013 compared to unrealized losses of $1.1 million for the three months ended September 30, 2012, increased margin by $8.8 million. Unrealized gains of $5.9 million for the nine months ended September 30, 2013 compared to unrealized losses of $3.1 million for the nine months ended September 30, 2012, increased margin by $9.0 million. Included in the 2013 gains is $6.0 million related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium.

For the three and nine months ended September 30, 2013, operating expenses increased $3.6 million and decreased $0.1 million compared to 2012. In the three months ended September 30, 2013, higher maintenance expenses at Four Corners and PNM's natural gas-fired plants increased operating expense $0.5 million and $0.2 million. In the nine months ended September 30, 2013, lower outage costs at PVNGS, SJGS, and PNM's natural gas-fired plants of $1.2 million, $0.3 million, and $1.1 million were partially offset by increased outage costs at Four Corners of $1.5 million. Lower labor, health care, pension, and retiree medical expenses reduced operating expenses by $0.5 million and $2.2 million for the three and nine months ended September 30, 2013 compared to 2012. Higher capitalized administrative and general expenses of $1.0 million and $2.0 million decreased operating expenses for the three and nine months ended September 30, 2013. Lower allocation of corporate expenses of $0.9 million due to business restructuring in 2012 reduced operating expenses for the nine months ended September 30, 2013. Improved collection experience in 2013 decreased bad debt expense by $0.4 million for the nine months ended September 30, 2013 further decreasing operating expenses. These decreases were partially offset in the three and nine months ended September 30, 2013 by higher incentive compensation expense of $0.8 million and $2.5 million and higher property, regulatory, and payroll taxes of $0.7 million and $1.8 million. In addition, during the three months ended September 30, 2013, PNM concluded that certain costs that had been deferred as regulatory assets were no longer probable of recovery and recorded a regulatory disallowance of $1.7 million increasing operating expenses compared to 2012.

For the three and nine months ended September 30, 2013, depreciation expense increased by $1.5 million and $5.8 million compared to 2012, primarily due to amortization of previously deferred costs related to the 22 MW of PNM-owned solar PV facilities, which are being recovered through a rate rider beginning in August 2012, as well as higher depreciation due to an increase in utility plant in service.

79

Other income (deductions) decreased $3.9 million and $4.3 million for the three and nine months September 30, 2013 compared to 2012. Lower income from investments held by the NDT decreased other income by $3.7 million and $1.9 million in the three and nine months ended September 30, 2013 compared to 2012. Lower interest income on PVNGS lessor notes of $0.6 million and $1.7 million reduced other income due to lower outstanding balances. During the three and nine months ended September 30, 2013, PNM made commitments of $0.8 million and $1.0 million to support employment and other economic activities in the "four corners" area, including the Navajo Nation, which further decreased earnings. These decreases were partially offset by higher equity AFUDC of $0.6 million and $0.2 million for the three and nine months ended September 30, 2013 compared to 2012.

For the three and nine months ended September 30, 2013, interest expense increased $0.9 million and $3.3 million compared to 2012, primarily due to the deferral in 2012 of interest costs associated with the 22 MW of PNM-owned solar PV facilities, which are now being recovered through a rate rider.

TNMP

The following table summarizes the operating results for TNMP:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Change			2013			2012			Change
	(In millions)
Electric operating revenues	$	73.7		$	68.7		$	5.0		$	201.4		$	187.4		$	14.0
Cost of energy	14.5			11.6			2.9			41.3			34.3			7.0
Margin	59.2			57.1			2.1			160.1			153.1			7.0
Operating expenses	23.1			22.3			0.8			67.3			64.2			3.1
Depreciation and amortization	13.9			13.8			0.1			37.8			37.2			0.6
Operating income	22.3			21.0			1.3			55.0			51.7			3.3
Other income (deductions)	0.7			0.4			0.3			1.4			1.2			0.2
Net interest charges	(6.7		)	(7.0		)	0.3			(20.7		)	(21.2		)	0.5
Segment earnings before income taxes	16.3			14.3			2.0			35.7			31.7			4.0
Income (taxes)	(6.2		)	(5.2		)	(1.0		)	(13.6		)	(11.6		)	(2.0		)
Segment earnings	$	10.1		$	9.1		$	1.0		$	22.2		$	20.1		$	2.1

The following table summarizes the significant changes to total electric operating revenues, cost of energy, and margin:

	2012/2013 Change
	Three Months Ended September 30,								Nine Months Ended September 30,
	Electric								Electric
	Operating			Cost of					Operating			Cost of
	Revenues			Energy		Margin			Revenues			Energy		Margin
	(In millions)
Rate increases	$	1.4		$	—	$	1.4		$	3.4		$	—	$	3.4
Customer usage/load	0.5			—		0.5			1.2			—		1.2
Customer growth	0.4			—		0.4			1.2			—		1.2
Demand based customers	1.0			—		1.0			2.6			—		2.6
Weather	(0.1		)	—		(0.1		)	(1.4		)	—		(1.4		)
Recovery of third-party transmission costs	2.9			2.9		—			7.4			7.0		0.4
AMS surcharge	(0.1		)	—		(0.1		)	2.0			—		2.0
CTC surcharge	(1.0		)	—		(1.0		)	(2.8		)	—		(2.8		)
Other	—			—		—			0.4			—		0.4
Net change	$	5.0		$	2.9	$	2.1		$	14.0		$	7.0	$	7.0

80

The following table shows total electric operating revenues by retail tariff consumer class, including intersegment revenues, and average number of consumers:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013		2012		Change		2013		2012		Change
	(In millions, except consumers)
Residential	$	36.4	$	33.2	$	3.2	$	84.1	$	79.9	$	4.2
Commercial	24.0		22.7		1.3		69.8		65.1		4.7
Industrial	3.2		3.2		—		9.6		10.1		(0.5		)
Other	10.1		9.6		0.5		37.9		32.3		5.6
	$	73.7	$	68.7	$	5.0	$	201.4	$	187.4	$	14.0
Average consumers (thousands) (1)	235.3		233.6		1.7		234.7		232.7		2.0

⁽¹⁾  TNMP provides transmission and distribution services to REPs that provide electric service to consumers 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.

The following table shows GWh sales by retail tariff consumer class:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013	2012	Change		2013	2012	Change
	(Gigawatt hours)
Residential	963.6	930.4	33.2		2,176.2	2,173.4	2.8
Commercial	714.7	692.5	22.2		1,854.2	1,796.7	57.5
Industrial	686.1	695.4	(9.3	)	1,920.3	2,025.6	(105.3	)
Other	27.6	26.5	1.1		77.3	78.0	(0.7	)
	2,392.0	2,344.8	47.2		6,028.0	6,073.7	(45.7	)

For the three and nine months ended September 30, 2013, revenues and margin increased by $1.4 million and $3.4 million compared to 2012 due to transmission cost of service rate increases in September 2012, March 2013, and September 2013. See Note 10. TNMP experienced positive year to date average customer growth of 0.9%. Weather had only minor impacts on results for the third quarter of 2013, but milder weather in the second quarter of 2013 compared to 2012 resulted in decreased revenues and margin of $1.4 million for the nine months ended September 30, 2013. For the three and nine months ended September 30, 2013, TNMP's weather normalized and leap-year adjusted retail KWh sales are up 3.3% and 1.9%. However, total retail KWh sales, excluding normalization, increased 2.0% and decreased 0.8% for the three and nine months ended September 30, 2013 compared to 2012.

Demand based revenues and margin for the three and nine months ended September 30, 2013 increased by $1.0 million and $2.6 million compared to 2012. This primarily results from TNMP, under a PUCT approved tariff, lowering the power factor billing threshold from 700 KW to 300 KW.

The AMS surcharge decreased revenues and margin by $0.1 million for the three months and increased revenues and margins by $2.0 million for the nine months 2013 compared to 2012, which amounts are offset by changes in operating expenses and depreciation. A decrease in the CTC surcharge rate decreased revenues and margin by $1.0 million and $2.8 million for the three and nine months ended September 30, 2013 compared to 2012, which amounts are offset by decreases in depreciation and amortization expense.

Customer related expense and administrative and general expense associated with the installation of additional meters under the AMS deployment decreased operating expenses $0.7 million for the three months and increased operating expense $0.5 million for the nine months ended September 30, 2013 compared to 2012. Higher property and sales tax expense of $0.6 million and $1.2 million increased operating expenses for the three and nine months ended September 30, 2013. Higher energy efficiency program expense of $0.4 million and $1.1 million increased operating expenses for the three and nine months ended September 30, 2013

81

compared to 2012, which amounts are offset by increases in operating revenue under TNMP's energy efficiency cost recovery factor. Higher employee benefits expense of $0.3 million and $0.6 million and higher incentive compensation expense of $0.2 million and $0.9 million also increased operating expenses for the three and nine months ended September 30, 2013 compared to 2012.

Depreciation expense associated with the AMS deployment, which is recovered through the AMS surcharge, increased $0.4 million and $1.2 million for the three and nine months ended September 30, 2013 compared to 2012. In addition, an increase in utility plant in service increased depreciation by $0.3 million and $1.0 million for the three and nine months ended September 30, 2013 compared to 2012. These increases are offset by lower amortization of the CTC regulatory asset of $0.8 million and $2.0 million for the three and nine months ended September 30, 2013 compared to 2012.

In April 2013, TNMP exchanged $93.2 million of its 9.5% First Mortgage Bonds for an equal amount of a new series of 6.95% First Mortgage Bonds. This resulted in decreases in interest expense of $0.6 million and $1.1 million during the three and nine months ended September 30, 2013, which were partially offset by increases in interest expense on short-term debt. See Note 8.

Corporate and Other

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Change			2013			2012			Change
	(In millions)
Total revenues	$	—		$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—			—
Margin	—			—			—			—			—			—
Operating expenses	(3.3		)	(4.8		)	1.5			(10.2		)	(12.7		)	2.5
Depreciation and amortization	3.0			4.6			(1.6		)	9.6			13.1			(3.5		)
Operating income (loss)	0.3			0.2			0.1			0.6			(0.4		)	1.0
Other income (deductions)	(3.5		)	(0.9		)	(2.6		)	(7.5		)	(4.9		)	(2.6		)
Net interest charges	(3.6		)	(4.2		)	0.6			(11.6		)	(12.4		)	0.8
Segment earnings (loss) before income taxes	(6.8		)	(4.9		)	(1.9		)	(18.6		)	(17.8		)	(0.8		)
Income (taxes) benefit	3.6			2.9			0.7			4.1			8.9			(4.8		)
Segment earnings (loss)	$	(3.2	)	$	(2.0	)	$	(1.2	)	$	(14.4	)	$	(8.9	)	$	(5.5	)

Operating expenses for Corporate and Other are net of amounts allocated to PNM and TNMP under shared service agreements. Changes in depreciation and amortization are offset in operating expenses as a result of allocation of these costs to other business segments.

For the three and nine months ended September 30, 2013, depreciation and amortization decreased compared to 2012, primarily due to expenses of $1.5 million and $3.5 million of amortization of leasehold improvements for part of the Company's headquarters building that was abandoned and fully amortized during 2012. PNM and TNMP deferred their allocations of the accelerated amortization of leasehold improvements as regulatory assets to be recovered through rates. The related increases in operating expenses were offset by decreases in expenses for legal and consulting incurred in 2012 related to the Company's union negotiations and the restructuring of outsourcing arrangements for information technology, both of which did not recur in 2013, as well as the allocation of additional costs to PNM and TNMP in 2013, which were included in Corporate and Other in 2012.

The change in other income (deductions) during the three months and nine months ended September 30, 2013 is primarily due to losses related to premiums of $1.8 million and $3.0 million paid in 2013 for the repurchase of $14.7 million and $23.0 million principal amounts of PNMR's 9.25% Senior Unsecured Notes, Series A, due 2015. These repurchases were also primarily responsible for the decrease in net interest charges for the three and nine months ended September 30, 2013. In addition, other income (deductions) for the three and nine months ended September 30, 2012 included a pretax gain of $1.0 million resulting from the sale of First Choice recorded in September 2012. The gain on the sale of First Choice is partially offset by lower performance on other investments during the first six months of 2012 compared to 2013.

82

During the first six months of 2013, income (taxes) benefit for Corporate and Other included the impairment of New Mexico wind energy production tax credits of $3.9 million, after federal income tax benefit, and an expense of $1.2 million due to reductions in Corporate and Other's deferred tax assets resulting from newly-enacted legislation reducing future New Mexico corporate income tax rates. No such impairments or changes occurred in the three months ended September 30, 2013 or the nine months ended September 30, 2012. See Note 13.

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR's cash flows for the nine months ended September 30, 2013 compared to September 30, 2012 are summarized as follows:

	Nine Months Ended September 30,
	2013			2012			Change
	(In millions)
Net cash flows from:
Operating activities	$	311.0		$	205.0		$	106.0
Investing activities	(211.4		)	(188.0		)	(23.4		)
Financing activities	(75.1		)	(26.8		)	(48.3		)
Net change in cash and cash equivalents	$	24.5		$	(9.7	)	$	34.2

The increase in PNMR's cash flows from operating activities relate to income tax refunds received of $95.5 million in 2013 compared to income taxes paid of $5.3 million in 2012 and $22.0 million lower contributions to the PNM and TNMP pension and other postretirement benefit plans in 2013 than in 2012. In addition, rate increases at TNMP and for two of PNM's firm-requirements wholesale customers, along with other changes in assets and liabilities resulting from normal operations increased operating cash flows. These increases were offset by refunds of $15.2 million made to customers related to the settlement of PNM's transmission rate case in 2013, $21.6 million of governmental grants received by PNM in 2012 that did not recur in 2013, and lower retail load at PNM.

The changes in PNMR's cash flows from investing activities relate primarily to an increase of $19.2 million in utility plant additions in the nine months ended September 30, 2013 compared to 2012. Utility plant additions at PNM were $20.1 million higher in the nine months ended September 30, 2013 than 2012, including increases in transmission and distribution additions of $33.9 million and renewable energy additions of $4.5 million. These increases were offset by $8.2 million lower nuclear fuel purchases, due to the acceleration of fuel deliveries in 2012 related to the financial difficulties of a supplier, and lower generation additions of $10.1 million. TNMP utility plant additions increased $7.6 million in the nine months ended September 30, 2013 compared to 2012, including increases in AMS additions of $4.4 million and other transmission and distribution additions of $3.2 million. Corporate plant additions decreased $8.5 million in the nine months ended September 30, 2013, primarily related to improvements made to the Company's corporate headquarters building in 2012. Proceeds from the sale of First Choice of $4.0 million received in 2012 included in investing activities also contributed to the change in cash flows.

The changes in cash flows from financing activities include a $77.4 million reduction in net short-term borrowings in the nine months ended September 30, 2013 compared to 2012. The decrease in short-term borrowings reflects the utilization of the tax refunds received in 2013. Cash flows from financing activities in 2013 also includes long-term borrowings of $75.0 million made at PNM, In addition, $13.0 million was paid in connection with TNMP's debt exchange and $26.0 million was paid by PNMR to repurchase $23.0 million of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, in 2013.

Financing Activities

See Note 6 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K, for additional information concerning the Company's financing activities.

In December 2012, PNMR entered into the PNMR Term Loan Agreement, which must be repaid on or before December 27, 2013, borrowed $100.0 million under that agreement, and used the funds to repay $100.0 million in borrowings made under

83

the PNMR Revolving Credit Facility. PNMR anticipates that funds to repay the PNMR Term Loan Agreement at maturity will come from entering into a new arrangement similar to the PNMR Term Loan Agreement, borrowing under the PNMR Revolving Credit Agreement, or a combination of these sources. On April 22, 2013, PNM entered into the PNM Term Loan Agreement, which must be repaid on or before October 21, 2014, borrowed $75.0 million under that agreement, and used the funds to repay $75.0 million in borrowings made under the PNM Revolving Credit Facility. At September 30, 2013, average interest rates were 1.31% for the PNMR Term Loan Agreement and 1.44% for the PNM Term Loan Agreement.

The TNMP Revolving Credit Facility is a $75.0 million facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. On September 18, 2013, the TNMP Revolving Credit Facility was amended and restated extending its maturity date from December 16, 2015 to September 18, 2018.

Each of the term loans, as well as the PNMR Revolving Credit Facility, the PNM Revolving Credit Facility, and the TNMP Revolving Credit Facility, contain one financial covenant, which requires the maintenance of debt-to-capital ratios of less than or equal to 65%.  These ratios for PNMR and PNM include the present value of payments under the PVNGS and EIP leases as debt.

On March 6, 2013, TNMP commenced an offer to exchange any and all of TNMP's $265.5 million aggregate principal amount outstanding 9.50% First Mortgage Bonds, due 2019, Series 2009A, for a new series of 6.95% First Mortgage Bonds due 2043, Series 2013A, and up to $140 in cash for each $1,000 of bonds exchanged. Settlement of the exchange offer occurred on April 3, 2013. Upon settlement, TNMP issued $93.2 million of 6.95% First Mortgage Bonds and paid an aggregate of $13.0 million in cash in exchange for $93.2 million of 9.50% First Mortgage Bonds, in addition to payment of accrued and unpaid interest on the exchanged bonds. The exchange resulted in the recording of a $23.2 million premium on the 6.95% First Mortgage Bonds reflecting the contractual interest rate being in excess of the market rate of interest on the date of the exchange. A regulatory asset was recorded offsetting the premium and the cash consideration paid in the exchange.

In the nine months ended September 30, 2013, PNMR purchased $23.0 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, for $26.0 million plus accrued and unpaid interest.

On October 2, 2013, the NMPRC approved PNM's application to enter into a new revolving credit facility of up to $50.0 million with banks operating in New Mexico. PNM anticipates entering into a facility in late 2013.

In October 2013, the second of the two one-year extension options for the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility were exercised extending the expiration of both facilities to October 31, 2018.

Capital Requirements

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 and additional renewable energy projects

• Expanding the electric transmission and distribution systems

• Purchasing nuclear fuel

Projected capital requirements, including amounts expended through September 30, 2013, are:

	2013		2014-2017		Total
	(In millions)
Construction expenditures	$	351.9	$	1,438.2	$	1,790.1
Dividends on PNMR common stock	51.0		210.3		261.3
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	403.4	$	1,650.6	$	2,054.0

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 additional renewable resources anticipated to be required to meet the RPS, additional peaking resources needed to meet needs outlined in PNM's current IRP, and environmental upgrades at Four Corners of $71.9 million estimated to be expended through 2017. The construction expenditures above do not include any amounts related to environmental upgrades at SJGS that ultimately may be required by EPA to address regional haze or expenditures

84

that could be required to replace capacity should environmental control at SJGS involve shutdown of one or more SJGS units. See Note 10 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 2012 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, 2013, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements.

In addition to the capital requirements for construction expenditures and dividends, the Company has long-term debt that must be paid or refinanced at maturity. Note 6 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K contains information about the maturities of long-term debt. 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 or enter into other liquidity arrangements in the future.

Liquidity

PNMR's liquidity arrangements include the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility that both expire in October 2018 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. The Company believes the terms and conditions of its facilities are consistent with those of other investment grade revolving credit facilities in the utility industry. 

The revolving credit facilities provide short-term borrowing capacity and 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 zero to $71.8 million during the three months ended September 30, 2013 and from zero to $84.0 million during the nine months ended September 30, 2013. PNM had no borrowings under the PNM Revolving Credit Facility during the three months ended September 30, 2013 and borrowings ranged from zero to $130.8 million during the nine months ended September 30, 2013. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $34.0 million during the three months ended September 30, 2013 and from zero to $40.0 million during the nine months ended September 30, 2013. At September 30, 2013, the average interest rate was 1.30% for the TNMP Revolving Credit Facility.

The Company currently believes that its capital requirements can be met through internal cash generation, existing or new credit arrangements, and access to public and private capital markets. To cover the difference in the amounts and timing of internal cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements. However, if difficult market conditions experienced during 2008 and 2009 return or worsen, 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 may 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 through 2017. This could include debt refinancing, new debt issuances, and/or new equity.

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 its investments

•Results of operations

•Ability to obtain required regulatory approvals

•Conditions in the financial markets

•Credit ratings 

85

The credit ratings for PNMR, PNM, and TNMP were set forth under the heading Liquidity in the MD&A contained in the 2012 Annual Reports on Form 10-K. On April 5, 2013, S&P raised the corporate credit ratings and the senior debt ratings for PNMR, PNM, and TNMP, as well as the preferred stock rating for PNM. S&P retained the outlook as stable for all entities. On June 21, 2013, Moody's changed the ratings outlook for PNMR, PNM, and TNMP to positive from stable. As of October 25, 2013, ratings on the Company's securities were as follows:

	PNMR	PNM	TNMP
S&P
Senior secured debt	*	*	A-
Senior unsecured debt	BBB-	BBB	*
Preferred stock	*	BB+	*
Moody's
Senior secured debt	*	*	A3
Senior unsecured debt	Ba1	Baa3	*
Preferred stock	*	Ba2	*

* Not applicable

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, which do not include the PNMR Term Loan Agreement or the PNM Term Loan Agreement, as of October 25, 2013 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
Amounts outstanding as of October 25, 2013:
Revolving credit facility	—		—		7.0		7.0
Letters of credit	8.6		3.2		0.3		12.1
Total short–term debt and letters of credit	8.6		3.2		7.3		19.1
Remaining availability as of October 25, 2013	$	291.4	$	396.8	$	67.7	$	755.9
Invested cash as of October 25, 2013	$	6.5	$	15.7	$	—	$	22.2

The above table excludes intercompany debt. 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.

For offerings of securities registered with the SEC, PNMR has a shelf registration statement expiring in March 2014. This shelf registration statement has unlimited availability and can be amended to include additional securities, subject to certain restrictions and limitations. PNMR can also offer new shares of common stock through the PNM Resources Direct Plan under a separate SEC shelf registration statement that expires in August 2015. PNM has a shelf registration statement for up to $440.0 million of senior unsecured notes that will expire in May 2014.

Off-Balance Sheet Arrangements

PNMR's off-balance sheet arrangements include PNM's operating lease obligations for PVNGS Units 1 and 2, the EIP transmission line, and Delta. 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, 9, and 16 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K. See Note 4 for additional information concerning the PVNGS Leases and Delta. See Note 10 for additional information concerning the EIP transmission line.

86

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 2012 Annual Reports on Form 10-K.

Contingent Provisions of Certain Obligations

As discussed in the 2012 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, 2013		December 31, 2012
PNMR
PNMR common equity	48.6	%	48.9	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	51.1	%	50.8	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	49.6	%	50.5	%
Preferred stock	0.4	%	0.5	%
Long-term debt	50.0	%	49.0	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	58.9	%	59.8	%
Long-term debt	41.1	%	40.2	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

According to EPA, gases that trap heat in the atmosphere are called greenhouse gases. The four primary greenhouse gases are CO₂, methane, nitrous oxide, and fluorinated gases, including chlorofluorocarbons such as freon. In 2012, GHG associated with PNM's interests in generating plants were approximately 6.7 million metric tons of CO₂, which comprises the vast majority of PNM's GHG.  By comparison, the total GHG in the United States in 2011, the latest year for which EPA has published this data, were approximately 6.7 billion metric tons, of which approximately 5.6 billion metric tons were CO₂.

PNM has several programs underway to reduce or offset its GHG from its resource portfolio, thereby reducing its exposure to climate change regulation. See Note 11. In 2011, PNM completed construction of 22 MW of utility-scale solar generation

87

located at five sites on PNM's system throughout New Mexico. In 2013, PNM is expanding its renewable energy portfolio by constructing 21.5 MW of utility-scale solar generation that will be online by the end of the year. On July 1, 2013, PNM filed its 2014 renewable energy procurement plan with the NMPRC that requests approval for construction of an additional 23 MW of utility-scale solar generation. If the plan is approved, the proposed generation will be online by the end of 2014. Since 2003 PNM has purchased the entire output of the 204 MW New Mexico Wind Energy Center and also included in the 2014 plan is a request for approval of the purchase of the full output of the 102 MW Red Mesa Wind Center beginning in January 2015. PNM has signed a 20-year PPA for the output of a 10 MW geothermal facility to be in service in 2014. Additionally, PNM has a customer distributed solar generation program that represented almost 20 MW at the end of 2012. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a 2012 budget of over $17 million, that PNM estimates saved approximately 79 GWh of electricity in 2012. Over the next 18 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 12,185 GWh of electricity, which will avoid at least 6.1 million metric tons of CO₂ based upon projected emissions from PNM's system-wide resources. These estimates are subject to change based upon the difficulty in accurately estimating avoidance because of the high uncertainty of many of the underlying variables and complex interrelationships between those variables, including changes in demand for electricity.

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 potential financial consequences that might result from potential federal and/or state regulation of GHG.

As of December 31, 2012, approximately 81.8% of PNM's owned and leased generating capacity, 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 10, on February 15, 2013, PNM, NMED, and EPA agreed to pursue a strategy to address the regional haze requirements of the CAA at the coal-fired SJGS, which would include the shutdown of SJGS Units 2 and 3. The shutdown of Units 2 and 3 will result in a reduction of GHG of approximately 50 percent at SJGS. That agreement also contemplates that gas-fired generation would be built to partially replace the retired capacity. Although replacement power strategies have not been finalized, the reduction in GHG from the retirement of the coal-fired generation would be far greater than the increase in GHG from replacement with gas-fired generation. On September 5, 2013, the EIB unanimously approved a revised SIP submitted by NMED that encompassed the February 15, 2013 agreement and the revised SIP was submitted to EPA for approval on October 18, 2013. EPA action on the revised SIP is projected for late 2014.

Because of PNM's dependence on fossil-fueled generation, any 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 that cost 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 demand, relocate facilities to other areas with lower energy costs, or take other actions that ultimately will adversely impact PNM.

Given the geographic location of its facilities and customers, PNM generally has not been exposed to the extreme weather events and other physical impacts commonly attributed to climate change, with the exception of periodic drought conditions. Climate changes are generally not expected to have material consequences in the near-term. Drought conditions in northwestern New Mexico could impact the availability of water for cooling coal-fired generating plants. Water shortage sharing agreements have been in place since 2004, although no shortage has been declared due to sufficient precipitation in the San Juan River basin. PNM also has a supplemental water contract in place with the Jicarilla Apache Nation to help address any water shortages from primary sources. The contract expires on December 31, 2016.  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 TNMP-owned facilities, which disrupt the ability to transmit and/or distribute energy, hurricanes can temporarily reduce customers' usage and demand for energy.

EPA Regulation

In April 2007, the United States 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

88

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 is to "tailor" the applicability of two programs, PSD and Title V operating permit programs, to avoid impacting millions of small GHG emitters. The rule focuses on the largest sources of GHG, including fossil-fueled electric generating units. This program currently covers new construction projects that emit GHG of at least 100,000 tons per year (even if PSD is not triggered for other pollutants). In addition, modifications at existing facilities that increase GHG by at least 75,000 tons per year will be subject to PSD permitting requirements, even if they do not significantly increase emissions of any other pollutant. All of PNM's fossil-fueled generating plants are potentially subject to the Tailoring Rule because of the magnitude of non-GHG, but the existing plants do not have any currently planned projects that would trigger PSD permitting for GHG. Any newly constructed fossil-fired power plant would likely be subject to the Tailoring Rule.

On June 26, 2012, the D.C. 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 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 United States Supreme Court granted a petition for a Writ of Certiorari regarding the permitting of stationary sources that emit GHG. The Supreme Court limited the question that it will be reviewing 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 deals 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 that it was required to regulate GHG under the PSD and Title V Programs was unlawful as it violates Congressional intent.

On March 27, 2012, EPA issued its proposed carbon pollution standards for GHG from new fossil-fueled electric generating units ("EGUs"). The proposed NSPS set a limit of 1,000 lb CO₂/MWh and would cover newly constructed fossil-fueled EGUs larger than 25 MW. The proposed limit was based on the performance of natural gas combined cycle technology. Therefore, coal-fired power plants would only be able to comply with the standard by using carbon capture and sequestration technology. The proposed rule included an exemption for simple cycle EGUs. EPA accepted comment on the proposed rule through June 25, 2012 during which EPA received over 2.5 million comments on the proposed rule.

On June 25, 2013, President Obama announced the President's 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 an GHG NSPS for new sources and a timeline for the proposal and final rule for developing carbon pollution standards, regulations or guidelines for GHG reductions from existing sources. EPA met the President's timeline for the reproposal of the GHG NSPS for new sources by releasing the draft rule on September 20, 2013. In accordance with the Presidential Memorandum, EPA will issue a final rule in "a timely fashion thereafter." EPA is also directed to issue the proposed GHG NSPS for modified and existing EGUs by June 1, 2014 and issue the final rule by June 1, 2015. Each state then must submit a SIP that addresses how the state will comply with the new regulation no later than June 30, 2016.

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 they are developed and implemented in a manner that provides for reliable and affordable energy and 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's reproposed GHG NSPS for new sources published on September 20, 2013 apply only to new EGUs. The reproposed standard would revise requirements for new fossil-fired utility boilers, integrated gasification combined cycle units, combined and simple cycle turbines, and new sources meeting certain other criteria. New fossil fuel-fired utility boilers including coal-fired and integrated gasification combined cycle units would be required to meet an emissions limit of 1,100 pounds of CO₂ per MWh on a 12-operating month rolling average basis or an alternative limit of 1,000 to 1,050 pounds of CO₂ per MWh based on an 84-operating month average. New coal-fired facilities would only be able to meet the standard by using carbon capture and sequestration

89

technology. New combined or simple cycle gas turbines would be subject to an emission limit of either 1,000 or 1,100 pounds of CO₂ per MWh based on whether the rated capacity of the unit is above or below 850 million BTUs per hour. The reproposed GHG NSPS removed the blanket exemption for simple-cycle turbines and instead provided an exemption for units that sell to the transmission grid less than one-third of their potential electric output over a 3-year rolling average.

EPA regulation of GHG from large stationary sources will impact PNM's fossil-fueled EGUs. Impacts could involve investments in efficiency improvements and/or control technologies at the fossil-fueled EGUs. In setting existing source standards, EPA has historically used technology-based performance standards on emission rates. The only end-of-pipe emission control technology for coal and gas fired power plants available for GHG reduction is carbon capture and sequestration, which is not yet a commercially demonstrated technology. 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. It is also possible EPA may consider a broader range of emission reduction measures, such as fuel switching, end use energy efficiency, or renewable energy deployment. Additional GHG control technologies for existing EGUs may become viable in the future. The costs of such improvements or technologies could impact the economic viability of some plants.

The ultimate impact of EPA's regulation of GHG to PNM is unknown because the regulatory requirements, including BACT implications and NSPS requirements, are in draft form or are still developing. PNM estimates that implementation of the revised SIP for BART at SJGS, which requires the installation of SNCRs on Units 1 and 4 by January 2016 or 15 months after EPA approval of a revised SIP and the retirement of SJGS Units 2 and 3 by the end of 2017, will allow PNM on a system-wide basis to meet or exceed the President's GHG reduction goal of 17% below 2005 levels by 2020 if the goal is is to be applied on a utility-by-utility basis. The reduction in CO₂ emissions that will result from implementation of the revised SIP may allow PNM to meet future GHG regulations; however, until such regulations are finalized, PNM is uncertain of the requirements for compliance.

Federal Legislation

Prospects for enactment of legislation imposing a new or enhanced regulatory program to address climate change in Congress are unlikely in 2013, although there is growing interest among some policymakers in addressing climate change and there may be legislation in the future.  Instead, EPA is the primary venue for GHG regulation in the near future, especially for coal-fired units. PNM has assessed, and continues to assess, the impacts of potential climate change legislation or regulation on its business.  This assessment is preliminary, and future changes arising out of the legislative or regulatory process could impact the assessment significantly.  PNM's assessment includes assumptions regarding the specific GHG limits, the timing of implementation of these limits, the possibility of a cap and trade program including the associated costs and the availability of offsets, the development of technologies for renewable energy and to reduce emissions, 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, at best, are preliminary and speculative. However, based upon these assumptions, the enactment of climate change legislation 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 10.  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 demand for electricity.  PNM's assessment process is ongoing, but too preliminary and speculative at this time for the meaningful prediction of financial impact.

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 issued an order in June 2007, requiring 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.  However, PNM is required to use these prices for purposes of its IRP, and the prices may not reflect the costs that it ultimately will incur.  PNM's IRP filed with the NMPRC on July 18, 2011 (Note 11) showed that while consideration of the NMPRC required carbon emissions costs did not significantly change the resource decisions regarding future facilities over the next 20 years, it did slightly impact the projected in-service dates of some of the identified resources.  Much higher GHG costs than assumed in the NMPRC analysis are necessary to impact future resource decisions. The primary consequence of the standardized cost of carbon emissions was an increase to generation portfolio costs.

90

In recent years, New Mexico adopted regulations, which have since been repealed, that would directly limit GHG from larger sources, including EGUs, through a regional GHG cap and trade program and that would cap GHG from larger sources such as electric generation units. Although these rules have been repealed, PNM cannot rule out future state legislative or regulatory initiatives to regulate GHG.

On August 2, 2012, 33 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 23, 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 base year between 2005 and 2012. The proposed rule would use a credit system that provides credits for electricity production based on how much less than 1.0 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 early. 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 Company monitors international treaties and accords such as the Kyoto Protocol and the EU Emissions Trading System to determine potential impacts to their business activities.  The Company does not anticipate any direct impact near-term from international accords.

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 and are waiting for the request to be processed through NERC's standards development.

In July 2011, FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development.  Order 1000 calls for significant changes to the transmission process of WestConnect, an organization of utility companies providing transmission of electricity in the western region that includes PNM.  On October 11, 2012, PNM and other WestConnect participants filed modified versions of Attachment K to their transmission tariffs to meet Order 1000 regional compliance requirements. Thirteen intervention motions were filed, with several objecting to and/or protesting various provisions of the filings submitted by the WestConnect participants. On December 17, 2012, the WestConnect participants filed responses

91

to the issues raised by the intervenors. On March 22, 2013, FERC issued its order regarding PNM's and six other WestConnect FERC jurisdictional utilities compliance filings. FERC partially accepted many aspects of the filings including the governance structure that gives the transmission owners a veto authority over the regional plan and cost allocations. A major change directed by FERC is the requirement that the cost allocations be binding on identified beneficiaries and that a process be created that will result in a qualified developer being selected. WestConnect members are evaluating the order and will be required to submit revised filings. The WestConnect participants requested an extension of time to file updated compliance filings reflecting the March 22, 2013 FERC order regarding the original October 11, 2012 Attachment K submittals. On July 3, FERC issued an order granting the requests and extending the filing date to September 20, 2013. PNM and the other WestConnect FERC jurisdictional entities submitted compliance filings on September 20, 2013. On July 11, 2013 the WestConnect participants submitted an additional compliance filing to address the planning and cost allocation between WestConnect and other regions.

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 recordkeeping 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 expects to qualify for this exception. PNM also expects to be able to comply with its requirements under the Dodd-Frank Reform Act and related rules within the time frames required by the CFTC. However, as a result of the Dodd-Frank Reform Act and related rules, PNM's swap activities could be subject to increased costs, including from higher margin requirements. In addition, implementation of, and compliance with, the swaps provisions of the Dodd-Frank Reform Act and related rules by PNM's swap counterparties could result in increased costs. 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

On March 25, 2013, a petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for utility workers. On April 12, 2013, a second petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for meter technicians, who were not included in the original petition. Approximately 200 employees are covered by the petitions. Elections to determine whether the IBEW would represent the employees were held in May 2013.  The employees voted to unionize through both petitions and contract negotiations have begun. Subsequently, on June 25, 2013, a third petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to include a group of three relay technicians, who were not included in the original petition. In August 2013, the relay technicians voted to unionize and contract negotiations have begun.

See Notes 10 and 11 herein and Notes 16 and 17 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K for a discussion of commitments and contingencies and rate and regulatory matters.

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, 2013, there have been no significant changes with regard to the critical accounting policies disclosed in PNMR's, PNM's, and TNMP's 2012 Annual Reports on Forms 10-K. The policies disclosed included unbilled revenues, regulatory accounting, impairments, decommissioning costs, derivatives, pension and other postretirement benefits, accounting for contingencies, income taxes, and market risk.

92

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:

• The ability of PNM and TNMP to recover costs and earn allowed returns in regulated jurisdictions

• The ability of the Company to successfully forecast and manage its operating and capital expenditures

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

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

• The impacts on the electricity usage of the Company's customers due to performance of state, regional, and national economies and mandatory energy efficiency measures, weather, seasonality, and other changes in supply and demand

• The risk that reliability standards regarding available transmission capacity and other FERC rulemakings may negatively impact the operation of PNM's transmission system

• The performance of generating units, transmission systems, and distribution systems, which could be negatively affected by operational issues, extreme weather conditions, terrorism, and cybersecurity breaches

• 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

• Uncertainty surrounding the status of PNM's participation in jointly-owned generation projects resulting from the scheduled expiration of the operational and fuel supply agreements for the projects, including potential restructuring and approval issues at SJGS and Four Corners necessary for operational and environmental compliance matters

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

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

• Uncertainty regarding the requirements and related costs of decommissioning power plants and coal mines supplying certain power plants, as well as the ability to recover decommissioning costs from customers

• The Company's ability to access the financial markets, including disruptions in the credit markets, actions by ratings agencies, and fluctuations in interest rates

• The potential unavailability of cash from PNMR's subsidiaries due to regulatory, statutory, or contractual restrictions

• The impacts of decreases in the values of marketable equity securities maintained to provide for decommissioning, reclamation, pension benefits, and other postretirement benefits

93

• Commodity and counterparty credit risk transactions and the effectiveness of risk management

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

• Changes in applicable accounting principles

Any material changes to risk factors occurring after the filing of PNMR's, PNM's, and TNMP's 2012 Annual Reports on Form 10-K are disclosed in Item 1A, Risk Factors, in Part II of this Form 10-Q.

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

SECURITIES ACT DISCLAIMER

Certain securities described or cross-referenced in this report have not been registered under the Securities Act of 1933, as amended, or any state securities laws and may not be reoffered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933 and applicable state securities laws. This Form 10-Q does not constitute an offer to sell or the solicitation of an offer to buy any securities.

WEBSITES

The PNMR website, www.pnmresources.com, is an important source of Company information. New or updated information for public access is routinely posted.  PNMR encourages analysts, investors, and other interested parties to register on the website to automatically receive Company information by e-mail. This information includes news releases, notices of webcasts, and filings with the SEC. Participants can unsubscribe at any time and will not receive information that was not requested.

Our Internet addresses are:

• PNMR: www.pnmresources.com

• PNM: www.pnm.com

• TNMP: www.tnmp.com

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/investors/governance.cfm 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 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:

• Establishment of policies regarding risk exposure levels and activities in each of the business segments

• Approval of the types of derivatives entered into for hedging

• Review and approval of hedging risk activities

94

• Establishment of policies regarding counterparty exposure and limits

• Authorization and delegation of transaction limits

• Review and approval of controls and procedures for derivative activities

• Review and approval of 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.

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 5, 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, 2013 and the year ended December 31, 2012, PNMR and PNM had no commodity derivative instruments designated as cash flow hedging instruments.

Commodity contracts that meet the definition of a derivative under GAAP, other than 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 PNMR's net asset or liability balance sheet position for mark-to-market energy transactions:

	Nine Months Ended
	September 30,
	2013			2012
Economic Hedges	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	1,204		$	(356	)
Amount realized on contracts delivered during period	(306		)	(3,695		)
Changes in fair value	6,164			619
Net mark-to-market change recorded in earnings	5,858			(3,076		)
Net change recorded as regulatory assets and liabilities	601			(42		)
Net fair value at end of period	$	7,663		$	(3,474	)

The following table provides the maturity of PNMR's net assets (liabilities) other than cash flow hedges, giving an indication of the calendar year in which these mark-to-market amounts will settle and generate (use) cash.

Fair Value of Mark-to-Market Instruments at September 30, 2013

	Settlement Dates
	2013		2014		2015		2016
	(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—	$	—	$	—
Prices provided by other external sources	1,298		4,464		2,269		(368		)
Prices based on models and other valuations	—		—		—		—
Total	$	1,298	$	4,464	$	2,269	$	(368	)

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 and 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

95

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 that are not covered by a FPPAC. For the nine months ended September 30, 2013, the high, low, and average VaR amounts were $1.4 million, $0.6 million, and $1.0 million. For the year ended December 31, 2012, the high, low, and average VaR amounts were $1.4 million, $0.3 million, and $0.6 million. At September 30, 2013 and December 31, 2012, the VaR amounts for the PNM wholesale portfolio were $0.7 million and $0.5 million.

The VaR limits, which were not exceeded during the nine months ended September 30, 2013 or the year ended December 31, 2012, represent 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 are 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.

Credit Risk

The Company is exposed to credit risk from its retail and wholesale customers, as well as 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 PNMR's credit exposure by the credit worthiness (credit rating) and concentration of credit risk for counterparties to derivative transactions. All credit exposures at September 30, 2013 will mature in less than two years, except for $0.8 million that matures in the fourth quarter of 2015.

Schedule of Credit Risk Exposure

September 30, 2013

Rating(1)	Credit Risk Exposure(2)		Number of Counter-parties >10%	Credit Risk Exposure of Counter-parties >10%
	(Dollars in thousands)
External ratings:
Investment grade	$	12,644	2	$	11,281
Non-investment grade	—		—	—
Split ratings	—
Internal ratings:
Investment grade	548		—	—
Non-investment grade	88		—	—
Total	$	13,280		$	11,281

⁽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, 2013, PNMR held no credit collateral to offset its credit exposure.

The Company provides for losses due to market and credit risk. Net credit risk for the Company's largest counterparty as of September 30, 2013 was $7.5 million.

The PVNGS lessor notes are not exposed to credit risk, since the notes are repaid as PNM makes payments on the underlying leases. Other investments have no significant counterparty credit risk.

96

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 3.6%, or $69.3 million, if interest rates were to decline by 50 basis points from their levels at September 30, 2013. 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. TNMP has long-term debt of $50.0 million that bears interest at a variable rate. However, TNMP has also entered into a hedging arrangement that effectively results in this debt bearing interest at a fixed rate, thereby eliminating interest rate risk. At October 25, 2013, PNMR, PNM, and TNMP had zero, zero, and $7.0 million of short term debt outstanding under their revolving credit facilities, which allow for a maximum aggregate borrowing capacity of $300.0 million for PNMR, $400.0 million for PNM, and $75.0 million for TNMP. These facilities bear interest at variable rates, which averaged 1.30% for TNMP on October 25, 2013 borrowings. At October 25, 2013, PNMR had outstanding borrowings of $100.0 million under the PNMR Term Loan Agreement and PNM had outstanding borrowings of $75.0 million under the PNM Term Loan Agreement. The term loans bear interest at variable rates, which were 1.31% for PNMR and 1.44% for PNM at October 25, 2013. The Company is exposed to interest rate risk to the extent of future increases in variable interest rates.

The investments held by PNM in the NDT and trust for post-term reclamation of the coal mines serving SJGS had an estimated fair value of $211.4 million at September 30, 2013, of which 32.3% 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, 2013, the decrease in the fair value of the fixed-rate securities would be 3.4%, or $2.3 million.

PNM does not directly recover or return through rates any losses or gains on the securities, including equity investments discussed below, in the trusts for nuclear 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 ratemaking process to the extent applicable to regulated operations. PNM is at risk for shortfalls in funding of obligations due to investment losses, including those from the equity market risks discussed below to the extent not ultimately recovered through rates charged to customers.

Equity Market Risk

The NDT and the trust for post-term reclamation of the coal mines serving SJGS hold certain equity securities at September 30, 2013. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. At September 30, 2013, these equity securities were valued at $118.7 million. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $11.9 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, 2013 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.

97

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Notes 10 and 11 for information related to the following matters, for PNMR, PNM, and TNMP, incorporated in this item by reference.

Note 10

• The Clean Air Act - Regional Haze - SJGS

• The Clean Air Act - Regional Haze - Four Corners

• The Clean Air Act - Four Corners BART FIP Challenge

• The Clean Air Act - Regional Haze Challenges

• The Clean Air Act - SJGS Operating Permit Challenge

•

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

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

• WEG v. OSM NEPA Lawsuit

• Navajo Nation Environmental Issues

• Endangered Species Act

• Santa Fe Generating Station

• Continuous Highwall Mining Royalty Rate

• SJCC Arbitration

• Four Corners Severance Tax Assessment

• PVNGS Water Supply Litigation

• San Juan River Adjudication

• Complaint Against Southwestern Public Service Company

• Navajo Nation Allottee Matters

• TGP Complaint

Note 11

• PNM - Renewable Portfolio Standard

• PNM - Renewable Energy Rider

• PNM - Energy Efficiency and Load Management

• PNM - 2010 Electric Rate Case and FPPAC

• PNM - Integrated Resource Plan

• PNM - Emergency FFPAC

• PNM - Applications for Approvals to Purchase Delta

• PNM - Application for Approval of La Luz Generating Station

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

• PNM - Transmission Rate Case

• PNM - Formula Transmission Rate Case

• PNM - Tri-State Complaint

• PNM - Firm-Requirements Wholesale Customers

• TNMP - Advanced Meter System Deployment and Surcharge Request

• TNMP - Energy Efficiency

• TNMP - Transmission Cost of Service Rates

See also Climate Change Issues under Other Issues Facing the Company in MD&A. The third paragraphs 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, 2012.

98

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 December 8, 2009 (incorporated by reference to Exhibit 3.1 to PNMR's Current Report on Form 8-K filed December 11, 2009)
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

99

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:	November 1, 2013	/s/ Thomas G. Sategna
		Thomas G. Sategna
		Vice President and Corporate Controller
		(Officer duly authorized to sign this report)

100

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, 2013			2012			2011				2010				2009			2008
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	90,078		$	125,379		$	122,998			$	123,633			$	123,833		$	134,958
Amortization of debt premium, discount and expenses	2,826			4,023			3,695				4,627				5,430			6,386
Interest from discontinued operations (including capitalized interest)	—			—			—				—				1,027			13,758
Estimated interest factor of lease rental charges	4,215			5,585			6,665				6,888				7,034			7,894
Preferred dividend requirements of subsidiary	619			769			864				1,075				759			689
Total Fixed Charges	$	97,738		$	135,756		$	134,222			$	136,223			$	138,083		$	163,685
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	162,759		$	175,035		$	321,469			$	(63,379	)		$	94,751		$	(388,381	)
(Earnings) loss of equity investee	—			—			—				15,223				30,145			29,687
Earnings (loss) from continuing operations before income taxes, non-controlling interest, and investee earnings	162,759			175,035			321,469				(48,156		)		124,896			(358,694		)
Fixed charges as above	97,738			135,756			134,222				136,223				138,083			163,685
Interest capitalized	(3,520		)	(5,432		)	(2,697		)		(3,401		)		(7,743		)	(8,849		)
Non-controlling interest in earnings of Valencia	(10,904		)	(14,050		)	(14,047		)		(13,563		)		(11,890		)	(7,179		)
Preferred dividend requirements of subsidiary	(619		)	(769		)	(864		)		(1,075		)		(759		)	(689		)
Earnings Available for Fixed Charges	$	245,454		$	290,540		$	438,083			$	70,028			$	242,587		$	(211,726	)
Ratio of Earnings to Fixed Charges	2.51			2.14			3.26			1	0.51			2	1.76			N/M			3
1  Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2011 includes a pre-tax loss of $21.4 million due to the write-off of regulatory disallowances at PNM and TNMP. If those losses were 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 were also excluded, the Ratio of Earnings to Fixed Charges would have been 1.96.
2 The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $66.2 million for the year ended December 31, 2010. Earnings (loss) from continuing operations before income taxes and non-controlling interest includes a pre-tax loss of $188.2 million due to the impairment of PNMR's investment in an equity investee. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 1.90.
3 The ratio of earnings to fixed charges for the year ended December 31, 2008 is not meaningful since earnings available for fixed charges is negative. The shortfall in the earnings available to achieve a ratio of earnings to fixed charges of 1.00 amounted to $375.4 million for the year ended December 31, 2008.

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, 2013			2012			2011				2010			2009			2008
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	60,063		$	82,864		$	75,217			$	73,423		$	73,104		$	72,427
Amortization of debt premium, discount and expenses	1,412			1,818			1,325				1,274			1,336			4,345
Interest from discontinued operations (including capitalized interest)	—			—			—				—			1,027			13,758
Estimated interest factor of lease rental charges	2,718			3,743			4,139				4,103			4,517			4,553
Total Fixed Charges	$	64,193		$	88,425		$	80,681			$	78,800		$	79,984		$	95,083
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	145,604		$	156,314		$	105,965			$	107,288		$	45,627		$	(69,324	)
Fixed charges as above	64,193			88,425			80,681				78,800			79,984			95,083
Non-controlling interest in earnings of Valencia	(10,904		)	(14,050		)	(14,047		)		(13,563		)	(11,890		)	(7,179		)
Interest capitalized	(2,895		)	(4,314		)	(1,761		)		(2,811		)	(6,067		)	(7,363		)
Earnings Available for Fixed Charges	$	195,998		$	226,375		$	170,838			$	169,714		$	107,654		$	11,217
Ratio of Earnings to Fixed Charges	3.05			2.56			2.12			1	2.15			1.35			0.12			2
1 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 were excluded, the Ratio of Earnings to Fixed Charges would have been 2.33.
2 The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $83.9 million for the year December 31, 2008.

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, 2013			2012			2011				2010			2009			2008
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	18,603		$	26,233		$	27,914			$	28,632		$	25,609		$	17,861
Amortization of debt premium, discount and expenses	897			1,493			1,679				2,683			3,355			1,504
Estimated interest factor of lease rental charges	839			956			1,202				1,246			831			571
Total Fixed Charges	$	20,339		$	28,682		$	30,795			$	32,561		$	29,795		$	19,936
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes	$	35,724		$	42,099		$	36,138			$	26,026		$	20,151		$	2,335
Fixed charges as above	20,339			28,682			30,795				32,561			29,795			19,936
Interest capitalized	(344		)	(706		)	(593		)		(158		)	(1,144		)	(1,025		)
Earnings Available for Fixed Charges	$	55,719		$	70,075		$	66,340			$	58,429		$	48,802		$	21,246
Ratio of Earnings to Fixed Charges	2.74			2.44			2.15			1	1.79			1.64			1.07
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 were 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:	November 1, 2013	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:	November 1, 2013	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:	November 1, 2013	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:	November 1, 2013	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:	November 1, 2013	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, Thomas G. Sategna, 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:	November 1, 2013	By:	/s/ Thomas G. Sategna
			Thomas G. Sategna
			Vice President and Controller
			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, 2013, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on November 1, 2013 (“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:	November 1, 2013	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, 2013, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on November 1, 2013 (“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:	November 1, 2013	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, 2013, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on November 1, 2013 (“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:	November 1, 2013	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chief Executive Officer
			Texas-New Mexico Power Company
		By:	/s/ Thomas G. Sategna
			Thomas G. Sategna
			Vice President and Controller
			Texas-New Mexico Power Company

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company is also 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 occasionally enters into financial commitments in connection with its business operations. The Company is also involved in various legal and regulatory (Note 11) 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. Notwithstanding these facts, the Company has assessed these matters based on current information and made judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and 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. 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 2012 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 under the contract. In November 1997, the D.C. 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 PVNGS owners previously received a damages award for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007, through June 30, 2011, APS, as a co-owner of PVNGS, incurred additional damages due to DOE's continuing failure to remove spent nuclear fuel and high level waste from PVNGS. Activities in this legal proceeding are currently limited to review by the government of supporting information for APS's claim. PNM is unable to predict the outcome of this matter.

PNM estimates that it will incur approximately $42.8 million (in 2010 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, 2013 and December 31, 2012, PNM had a liability for interim storage costs of $12.4 million and $13.9 million included in other deferred credits.

On June 8, 2012, the D.C. 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. The D.C. Circuit found that the agency's 2010 Waste Confidence Decision update constituted a major federal action, which requires either an environmental impact statement or a finding of no significant impact from the agency's actions. The D.C. Circuit found that the NRC's evaluation of the environmental risks from spent nuclear was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action. In September 2012, the NRC issued a directive to its staff to proceed with development of a generic environmental impact statement to support an updated Waste Confidence Decision within 24 months. The petitioners had also sought a writ requiring the NRC to comply with the law and resume processing DOE's pending license application for a nuclear waste site at Yucca Mountain in Nevada. On August 13, 2013, the D.C. Circuit granted the writ and held that the NRC must continue reviewing the license application. PNM is unable to predict the impact of these decisions.

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 Determination Process - SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology ("SNCR"). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that requires installation of selective catalytic reduction technology ("SCR") with stringent NOx emission limits on all four units by September 21, 2016.

PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA's decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule on March 1, 2012. These parties have also formally asked EPA to stay the effective date of the rule. Several environmental groups have intervened in support of EPA. WEG also filed an action to challenge EPA's rule in the Tenth Circuit, seeking to shorten its compliance period from five years to three years and PNM has intervened in this action. Oral arguments on the merits of the FIP challenges were held in October 2012 in the Tenth Circuit. In accordance with the court's order, the parties have filed supplemental information. No decision has been announced and there is no deadline for a court decision.

In litigation involving several environmental groups, the United States District Court for the District of Columbia entered a consent decree, which, as amended, required EPA to issue a final rulemaking on New Mexico's regional haze SIP by November 15, 2012. EPA approved all components of the SIP, except for the NOx BART determination for SJGS. With respect to that element of the SIP, EPA determined that with the FIP in place, it had met its obligation under the consent decree.

Because the unchanged compliance deadline of the FIP required PNM to continue to take steps to commence installation of SCRs at SJGS, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, has been suspended through November 1, 2014. PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million, which amounts include costs for construction management, gross receipts taxes, AFUDC, and other PNM costs, although final costs would be refined through an "open book" subcontractor bidding process. The costs for the project to install SCRs would encompass installation of technology to comply with the NAAQS requirements described below.

PNM previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS. The estimates for SNCRs and the NAAQS requirements include gross receipts taxes, AFUDC, and other PNM costs.

Based upon its current SJGS ownership interest, PNM's share of the costs under either SCRs or SNCRs as described above would be about 46.3%.

During 2012 and early 2013, PNM engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS, subject to approval by EIB and EPA. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP.

NMPRC approval of the retirement of SJGS Units 2 and 3 and plans for PNM to acquire power to replace its reduced capacity from SJGS would also be part of implementation. PNM also anticipates requesting approval to recover from ratepayers the unrecovered investment in SJGS Units 2 and 3 and costs incurred to retire those units. PNM anticipates filing for the required NMPRC approvals in December 2013. On July 10, 2013, the NMPRC issued an order initiating a proceeding regarding the possible retirement of SJGS Units 2 and 3 and impacts on service reliability, and other items. The order requires PNM to make monthly presentations to the NMPRC on this matter. At September 30, 2013, PNM's net book value of SJGS Units 2 and 3 was approximately $287 million.

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013, reflecting the terms of the non-binding agreement, including the installation of SNCRs on Units 1 and 4 and the retirement of Units 2 and 3. NMED developed a revised SIP and submitted it to the EIB for approval in May 2013. After a public hearing, the EIB approved the revised SIP in September 2013 and the revised SIP was submitted to EPA for approval on October 18, 2013. EPA action on the revised SIP is projected for late 2014.

Due to the long lead times on certain equipment purchases, PNM is taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In April 2013, PNM issued an RFP for SNCR system design and technology. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider, but has not yet entered into a construction and procurement contract.

In connection with the implementation of the revised plan, retirement of SJGS Units 2 and 3 could result in shifts in ownership among SJGS owners as may be agreed upon by the owners. See SJGS Ownership Restructuring Matters below. Owners of the affected units also may seek approvals of their utility commissions or governing boards.

This revised plan primarily focuses on how SJGS would meet the regional haze rule, but also indicates that PNM would build a natural gas-fired generating plant to be sited at SJGS to partially replace the capacity from the retired coal units. Detailed replacement power strategies also would be finalized.  PNM believes adequate replacement power alternatives will be available to meet its generation needs and ensure reliability.

Contemporaneously with the signing of the non-binding agreement, EPA indicated in writing that if the terms agreed to do not move forward due to circumstances outside of the control of PNM and NMED, EPA will work with the State of New Mexico and PNM to create a reasonable FIP compliance schedule to reflect the time used to develop the revised SIP.

On February 25, 2013, the parties filed their status reports with the Tenth Circuit.  To demonstrate that progress has been made toward settling the Tenth Circuit litigation, information, including the non-binding agreement and its accompanying timeline, was submitted to the Tenth Circuit. Following the parties' submission of their status reports, on February 28, 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals. On October 17, 2013, the court ruled on a motion filed by PNM for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously filed motion to stay the EPA rule. The court placed the pending petitions for review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the agreement in principle fails or is not implemented as was indicated in the term sheet and timeline, any party to the litigation may file a motion seeking to lift the abatement.  PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

If the February 15, 2013 plan described above is implemented, PNM currently estimates its share of the costs to install SNCRs and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 would be approximately $60 million to $80 million, including gross receipts taxes, AFUDC, and other PNM costs. This amount is based on the anticipation that PNM's ownership share of SJGS Units 1 and 4 would aggregate to between approximately 52% and 55%. PNM also estimates that the cost of replacing a portion of PNM's share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3 with identified gas-fired or solar peaking capacity would be approximately $299 million. Neither of these amounts is included in PNM's current construction expenditure forecast since approval of the plan is subject to numerous conditions. Additional base load generating capacity may be required to replace a portion of retired SJGS capacity. The nature of additional base load capacity, which has not yet been identified, could come from some combination of PVNGS Unit 3, renewable resources, and/or additional gas-fired generation. 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 would increase with the installation of either SCRs or SNCRs. See Note11 for additional information concerning PNM's filing for NMPRC approvals regarding these matters.

PNM can provide no assurance that the requirements of the plan agreed to on February 15, 2013 will be accomplished at all or within the required timeframes. If the February 15, 2013 plan is not implemented, PNM would seek to work with NMED and EPA to develop a revised timetable for implementation of the FIP. If an agreement on a revised timetable cannot be reached, PNM will likely be unable to complete the installation of SCRs on all four units at SJGS by the FIP deadline of September 21, 2016. In such event, PNM would likely seek relief from the compliance deadline from EPA or the Tenth Circuit in order to continue to be able to operate the plant during the completion of the installation process. If relief is not granted, PNM could be forced to temporarily cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire temporary replacement power through short-term or open-market purchases in order to serve the needs of its customers. There can be no assurance that sufficient replacement power will be available to serve PNM's needs or, if available, what costs would be incurred.

PNM is unable to predict the ultimate outcome of these matters or what additional pollution control equipment will be required at SJGS.PNM will seek recovery from its ratepayers for all costs that may be incurred as a result of the CAA requirements. Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance the installation. It is possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation or legislation, if any, 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.

SJGS Ownership Restructuring Matters - As discussed in the 2012 Annual Reports on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The San Juan Project Participation Agreement ("SJPPA") that governs the operation of SJGS expires on July 1, 2022 and the contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. Accordingly, they believe they would be unable to fund the construction of either SCRs or SNCRs at SJGS. Therefore, the California participants have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA and sooner, if possible. One other participant has also expressed a similar intent to exit ownership in the plant.

The SJGS participants have engaged in negotiations concerning the implementation of the revised SIP to address BART at SJGS. The negotiations have included potential shifts in ownership among participants and between units in order to facilitate the shutdown of SJGS Units 2 and 3 to comply with the revised SIP and to accommodate the intent of the participants desiring to exit ownership in SJGS. This could result in the exiting participants' ownership interests in SJGS Unit 4 being shifted to SJGS Unit 3 and certain of the continuing participants, including PNM, acquiring additional ownership interests in Unit 4. In addition, the discussions regarding such a restructuring have included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs. Although discussions are continuing, no agreements have been reached.

The SJPPA requires PNM, as operating agent, to obtain approval of capital improvement project expenditures from participants who have an ownership interest in the relevant unit or common property. As provided in the SJPPA, specified percentages of both the outstanding participant shares, based on MW ownership, and the number of participants in the unit or common property must be obtained in order for a capital improvement project to be approved. PNM presented the SNCR project, including NAAQS compliance requirements, to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. The SJPPA provides that PNM is authorized and obligated to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM is evaluating its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants, but has not reached a decision on how to proceed. PNM cannot predict the outcome of this matter, its impact on SJGS' compliance with the CAA, or the impact on PNM's financial position and results of operations.

Four Corners

On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule includes two compliance alternatives. The first emission control strategy finalized by EPA would require the installation of post-combustion controls, including SCRs, on each of Units 1-5 at Four Corners to reduce NOx emissions. Under the second emission control alternative, the owners of Four Corners would have the option to close permanently 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. 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. Under the EPA's final BART determination, the Four Corners participants had until July 1, 2013 to notify EPA of which emission control strategy Four Corners would follow. Either alternative would involve substantial investment by the owners in additional post-combustion pollution controls and, accordingly, contemplates the continued operation of Four Corners for a substantial period of time. On September 24, 2013, EPA extended the date by which the Four Corners participants must notify EPA of their chosen BART compliance strategy from July 1 to December 31, 2013.

The Four Corners participants' obligations to comply with EPA's final BART determinations, coupled with the financial impact of possible future 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.

PNM is continuing to evaluate the impacts of EPA's BART determination for Four Corners. PNM estimates its share of costs, including PNM's AFUDC, to be up to approximately $75 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM has no ownership interest in Four Corners Units 1, 2, and 3. PNM is unable to predict the ultimate outcome of this matter.

SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at Four Corners. APS and SCE entered into an asset purchase agreement, providing for the purchase by APS of SCE's 48% interest in each of Units 4 and 5 of Four Corners. A principal remaining condition to closing is the negotiation and execution of a new coal supply contract for Four Corners on terms reasonably acceptable to APS. See Coal Supply below. APS has announced that, if APS's purchase of SCE's interests in Units 4 and 5 at Four Corners is consummated, it will shut down Units 1, 2, and 3 at Four Corners. On May 9, 2013, the Arizona Corporation Commission ("ACC"), which regulates APS, voted to re-examine the facilitation of a deregulated retail electric market in Arizona. In connection with this matter, APS announced that it would not be in a position to close the Four Corners purchase transaction with SCE until the ACC's intentions with regard to pursuing deregulation in Arizona became clearer. In September 2013, the ACC closed the deregulation docket. Certain parties have filed motions for rehearing, which are pending before the ACC. Pursuant to the asset purchase agreement, because all of the closing conditions were not originally satisfied by December 31, 2012, either APS or SCE has a right to terminate the agreement, unless the party seeking to terminate is then in breach. Although the ACC closed its deregulation docket, APS has reported that it cannot predict whether the closing conditions will be satisfied such that closing of its planned purchase of SCE's interest in Four Corners can occur.

Four Corners BART FIP Challenge

On October 22, 2012, WEG filed a petition for review in the Ninth Circuit challenging the Four Corners BART FIP.  In its petition, WEG alleges that the final BART rule results in more air pollution being emitted into the air than allowed by law and that EPA failed to follow the requirements of the ESA.  APS intervened in this matter and filed a motion to dismiss this lawsuit for lack of jurisdiction or alternatively to transfer the lawsuit to the Tenth Circuit. On February 25, 2013, the Ninth Circuit denied APS' motion to dismiss, but granted the request to transfer the case to the Tenth Circuit. This matter is now proceeding in the Tenth Circuit. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

Regional Haze Challenges

On December 27, 2012, WEG filed a petition for review in the Tenth Circuit challenging the SO₂ and particulate matter emissions elements of EPA's approval of New Mexico's Regional Haze SIP.  On February 26, 2013, HEAL Utah and other environmental groups filed petitions in the Tenth Circuit challenging EPA's final approval of the remaining elements of New Mexico's Regional Haze SIP, as well as EPA's approval of the Albuquerque/Bernalillo County Air Quality Control Board SIP. PNM was granted intervention in both matters and the Tenth Circuit consolidated the two matters based on the similarity of issues. This matter is now proceeding in the Tenth Circuit. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

SJGS Operating Permit Challenge

On February 16, 2012, EPA issued its response to a WEG petition objecting to SJGS's operating permit granted by the NMED in January 2011. In its order, EPA required NMED to provide clarification on several of the matters raised by WEG.  EPA's order in this matter does not constitute a finding that the plant has violated any provision of the CAA or that it has violated any emission limits. 

In August 2012, NMED issued a response to the EPA order stating that SJGS's operating permit would be reopened to make certain modifications to the permit. NMED issued a public notice regarding proposed modifications to the SJGS operating permit on September 19, 2012 and issued a revised operating permit on November 26, 2012. The revised permit includes changes to the SO₂ and particulate matter emission limits that were previously incorporated into the SJGS NSR permit. In addition, the revised permit requires PNM to submit a compliance plan to address carbon monoxide ("CO") emissions increases at SJGS Unit 2. PNM submitted a compliance plan in May 2013 and considers this matter resolved.

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. EPA has issued draft guidance on how to determine whether areas in a state comply with the new 1-hour SO₂ NAAQS. On May 21, 2013, EPA released draft guidance on characterizing air quality in areas with limited or no monitoring data near existing SO₂ sources. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO₂ NAAQS.  Although the determination process has not been finalized, PNM believes that compliance with the 1-hour SO₂ standard may require operational changes and/or equipment modifications at SJGS. On June 4, 2013, Sierra Club and National Resource Defense Council issued a NOI to sue EPA for failure to issue non-attainment designations for areas they claim to be in violation of the 2010 1-hour SO₂ standard. On April 6, 2012, PNM filed an application for an amendment to its air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. In addition, this application included a proposal by PNM to install equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO₂, and particulate matter. These modifications would help SJGS meet the NAAQS. It is anticipated that this technology would be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities at SJGS. The cost of this technology is dependent upon the type of control technology that is ultimately determined to be NOx BART at SJGS. See Regional Haze - SJGS above.

EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications discussed above will assist with the plant with compliance 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 0.060-0.070 parts per million. EPA is reviewing its 2008 standard and is scheduled to propose a new standard in December 2013 and finalize it by the end of 2014.  Depending upon where the standard for ozone is set, San Juan County, where SJGS is situated, could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. As a result, SJGS could be required to install further NOx controls to meet a new ozone NAAQS. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional NOx controls would be required as a result of ozone non-attainment designation.

Citizen Suit Under the Clean Air Act

The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS's emissions performance. In May 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties' dispute is deemed settled.

In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM's mercury controls. NMED and plaintiffs seek to require PNM to implement additional mercury controls. PNM estimates the implementation would increase annual mercury control costs for the entire station, which are currently $0.6 million, to a total of $6.1 million. The court appointed a special master to evaluate the technical arguments in the case and to address the detection and determination limits of the mercury monitors at SJGS and the appropriate brominated activated carbon injection rate that maximizes the reduction of mercury emissions from SJGS.  The special master issued a report indicating he was unable to make a determination on either of these issues.  In September 2012, PNM submitted objections to certain portions of the special master report and requested an evidentiary hearing. Also in September 2012, NMED and plaintiffs filed a motion asking the court to affirm certain findings in the special master report and order PNM to conduct additional mercury testing. The parties have provided status updates to the court as required. PNM cannot predict the outcome of this matter.

Section 114 Request

In April 2009, APS received a request from EPA under Section 114 of the CAA seeking detailed information regarding projects at and operations of Four Corners. EPA has taken the position that many utilities have made physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the CAA. APS has responded to EPA's request. PNM is currently unable to predict the timing or content of EPA's response, if any, or any resulting actions.

Four Corners Clean Air Act Lawsuit

In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, the Four Corners owners may reinstate their motions to dismiss without risk of default. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

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 National Environmental Policy Act 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 voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines, and enjoining operations at the seven mines. SJCC intervened in this matter and seeks to sever SJCC's claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

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.

Endangered Species Act

In January 2011, the Center for Biological Diversity, Diné Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit in the United States District Court for the District of Colorado against the OSM and the DOI, alleging that OSM failed to engage in mandatory ESA consultation with the United States Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners.  The lawsuit alleges that activities at the mine, including mining and the disposal of coal combustion residue, will adversely affect several endangered species and their critical habitats.  The lawsuit requested the court to vacate and remand the mining permit and enjoin all activities carried out under the permit until OSM has complied with the ESA.  Neither PNM nor APS was a party to the lawsuit. On March 14, 2012, the Court entered an order dismissing the plaintiffs' lawsuit without prejudice. On May 14, 2012, the plaintiffs appealed the Court's order to the Tenth Circuit. On July 8, 2013, the Tenth Circuit entered an order dismissing the appeal, which concludes this matter.

Cooling Water Intake Structures

EPA issued its proposed cooling water intake structures rule in April 2011, which would provide 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 proposed rule would require facilities such as Four Corners and SJGS to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity and to take certain protective measures with respect to impinged fish. The proposed rule would also require these facilities to either meet the definition of a closed cycle recirculating cooling system or conduct a "structured site-specific analysis" to determine what site-specific controls, if any, should be required.

The proposed rule would require existing facilities to comply with the impingement mortality requirements as soon as possible, but no later than eight years after the effective date of the rule, and to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. EPA was required to issue a final rule by June 27, 2013; however, that date has been extended to November 4, 2013. PNM and APS continue to follow the rulemaking and are performing analyses to determine the potential costs of compliance with the proposed rule. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance.

Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for steam electric power plants.  EPA's proposal offers 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 wastes operations.  EPA is subject to a consent decree deadline to finalize the revised guidelines by May 22, 2014. PNM is in the process of reviewing the proposed rule to assess the impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. APS is currently assessing the impact to Four Corners. PNM is unable to predict the outcome of this matter or if it will have a material impact on PNM's financial position, results of operations, or cash flows. 

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 the 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 municipal well continues to operate and meets federal drinking water standards. The City of Santa Fe has recently 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 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 also states that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM's obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced similar results. PNM is unable to predict the outcome of this matter and does not believe the former generating station is the source of the nitrates or the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made.

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. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production.  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 includes two options for waste designation of coal ash. One option is 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 is 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. EPA's proposal does not address the placement of CCBs in surface mine pits for reclamation. An OSM CCB rulemaking team has been formed to develop a proposed rule. 

On April 5, 2012, several environmental groups, including Sierra Club, filed a citizen suit in the D.C. Circuit claiming that EPA has failed to review and revise RCRA's regulations with respect to CCBs. The groups allege that EPA has already determined that revisions to the CCBs regulations are necessary. They also claim that EPA now has a non-discretionary duty to revise the regulations. The environmental groups asked the court to direct EPA to complete its review of the regulation of CCBs and a hazardous waste analytical procedure and to issue necessary revisions of such regulations as soon as possible. Two industry group members subsequently filed separate lawsuits in the D.C. Circuit seeking to ensure that disposal of coal ash would not be regulated as a hazardous waste. The environmental and industry lawsuits have been consolidated.

PNM advocates for the non-hazardous regulation of CCBs. However, if CCBs are ultimately regulated as a hazardous waste, costs could increase significantly. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of EPA's or OSM's proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material impact on its operations, financial position, or cash flows. 

Hazardous Air Pollutants ("HAPs") Rulemaking

In December 2011, the EPA issued its final Mercury and Air Toxics Standards ("MATS") to reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel, as well as acid gases, including hydrochloric and hydrofluoric gases, from coal and oil-fired electric generating units with a capacity of at least 25 MW. Existing facilities will generally have up to four years to demonstrate compliance with the new rule. PNM's assessment of MATS indicates that the control equipment currently used at SJGS allows the plant to meet the emission standards set forth in the rule although the plant may be required to install additional monitoring equipment. With regard to mercury, stack testing performed for EPA during the MATS rulemaking process showed that SJGS achieved a mercury removal rate of 99% or greater. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule. 

Other Commitments and Contingencies

Coal Supply

The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At September 30, 2013 and December 31, 2012, prepayments for coal, which are included in other current assets, amounted to $15.8 million and $9.9 million. These amounts reflect delivery of a portion of the prepaid coal and its utilization due to the mine fire incident described below. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement to supply processed coal for operation of SJGS through 2017. Under the coal sales agreement, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.

APS purchases all of Four Corners' coal requirements from a supplier that is also a subsidiary of BHP and has a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through July 6, 2016 with pricing determined using an escalating base-price. In December 2012, BHP announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which the coal mine would be sold to the Navajo Nation. The BHP subsidiary would be retained as the mine manager and operator until July 2016. Key terms of the new coal supply contract are being finalized by the Navajo Nation and the Four Corners owners. The Four Corners owners must finalize their approvals of the contract. These negotiations, and the related transaction whereby full ownership of the coal mine would be transferred to the Navajo Nation, are proceeding. On April 29, 2013, the Navajo Nation Tribal Council approved the creation of the new commercial enterprise with sufficient power and authority to execute the transaction with BHP. See The Clean Air Act - Regional Haze - Four Corners above. PNM is unable to predict the outcome of this matter.

In 2010, 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. The estimate for decommissioning the Four Corners mine was also revised in 2010. Based on the 2010 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $56.9 million for the surface mines at both SJGS and Four Corners and $19.7 million for the underground mine at SJGS as of September 30, 2013. At September 30, 2013 and December 31, 2012, liabilities, in current dollars, of $23.7 million and $26.8 million for surface mine reclamation and $4.6 million and $4.2 million for underground mine reclamation were recorded in other deferred credits.

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 ratepayers 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. In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA discussed under The Clean Air Act - Regional Haze - SJGS above, an updated coal mine reclamation study was requested by the SJGS participants. 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. Although the updated coal mine reclamation study has not been finalized, preliminary indications are that reclamation costs for both the surface and underground mines have increased, including significant increases due to the shutdown of SJGS Units 2 and 3. The shutdown of Units 2 and 3 would reduce the amount of CCBs generated over the remaining life of SJGS, which could result in a significant increase in the amount of fill dirt required to remediate the surface mine pits thereby increasing the overall reclamation costs. The amount of any increase and the allocation between the surface and underground mines cannot be determined at this time. Furthermore, it has not been decided how costs would be divided among the owners of SJGS, which may be dependent on the final decision regarding how SJGS ownership is restructured. 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 impact.

San Juan Underground Mine Fire Incident

On September 9, 2011, a fire was discovered at the underground mine owned and operated by SJCC that provides coal for SJGS. The federal Mine Safety and Health Administration ("MSHA") was notified of the incident. On September 12, 2011, SJCC informed PNM that the fire was extinguished. However, MSHA required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. SJCC regained entry into the sealed area of the mine in early March 2012. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. If further difficulties occur in the longwall mining operation, PNM and the other owners of SJGS would need to consider alternatives for operating SJGS, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time.

The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM anticipates that it will recover through its FPPAC the portion of such costs allocable to its customers subject to New Mexico regulation. PNM's filings with the NMPRC reflect an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by $21.6 million. SJCC submitted an insurance claim regarding the costs it incurred due to the mine fire and has informed PNM that it has settled with its insurance carrier. PNM believes the settlement proceeds obtained by SJCC through its insurance carrier are reimbursable (in whole or in part) to the owners of SJGS through the coal sales agreement. PNM's portion of the insurance recovery, which is estimated to be $18.7 million based on information received from SJCC, will be flowed through PNM's FPPAC to the extent it relates to increased coal costs included in the FPPAC.

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.

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 a settlement agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal.  The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed.  PNM's share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM's FPPAC. PNM is unable to predict the outcome of this matter.

SJCC Arbitration

The coal supply agreement for SJGS provides that the participants in SJGS have the right to audit the costs billed by SJCC. An independent accounting firm has been engaged to perform audits of the costs billed under the provisions of the contract. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC. As provided in the contract, certain issues have been submitted to a panel for binding arbitration. In October 2013, the arbitration panel ruled on one issue and set other issues for hearing. The panel ruled that the SJGS participants owe SJCC $1.5 million for disputed mining costs.  PNM's share of this amount is $0.7 million of which $0.5 million will be passed through PNM's FPPAC. The remaining issues going forward to a hearing include: 1) whether the SJGS participants owe SJCC unbilled mining costsof $5.2 million or whether SJCC owes the SJGS participants overbilled mining costs of $1.1 million, and 2) whether SJCC billed the SJGS participants $12.9 million as mining costs that SJCC should have considered to be capital improvements, which are not billable under the mining contract.  PNM's share of any amounts resulting from the arbitration would be approximately 46.3%. Of PNM's share of the costs, approximately 33% of the first remaining issue as well as approximately 25% of the second remaining issue would be passed through PNM's FPPAC and the rest would impact earnings. A hearing date on the remaining issues has not been set. PNM is unable to predict the outcome of the arbitration hearing.

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. PNM's share of any amounts paid related to this assessment would be approximately 8%, all of which would be passed through PNM's FPPAC. 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. The NMTRD denied the refund claim. Prior to year end, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, intend to file a complaint with the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. PNM believes the assessment and the refund claim denial are without merit, but cannot predict the outcome of this matter.

Nuclear Fuel

In late August 2012, one of PVNGS's suppliers that converts uranium concentrates to uranium hexafluoride invoked the force majeure provision in its contract when it shut down its conversion plant due to regulatory compliance issues. The issues have been resolved and the conversion plant has restarted. The PVNGS participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The PVNGS participants have sufficient strategic reserves of enriched uranium such that they do not anticipate a short-term impact on nuclear fuel supplies as a result of the force majeure declaration.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson 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 the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.6 billion per occurrence. Commercial insurance carriers provide $375 million and $13.2 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 assessment per incident for all three units is $38.9 million, with an annual payment limitation of $5.7 million.

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"). Effective April 1, 2013, a sublimit of $1.5 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 assessments of $4.3 million for each retrospective assessment declared by NEIL's Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions 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. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Delta, Afton, Luna, and Lordsburg. Water availability does not appear to be 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 allocations could pose a threat of reduced water availability for these plants.

PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines to accommodate the possibility of inadequate precipitation in coming years. Since 2004, PNM has entered into agreements for voluntary sharing of the impacts of water shortages with tribes and other water users in the San Juan basin. This agreement has been extended through 2016. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement with the Jicarilla Apache Nation on a supplemental contract relating to water for SJGS and Four Corners that runs through 2016. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather or its ramifications, or how policy, regulations, and legislation may impact PNM should water shortages occur in the future.

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 has ordered that settlement of the Navajo Nation's claims under the settlement agreement and entry of the proposed decrees be heard in an expedited proceeding.  The court recently issued an order finding that no evidentiary hearing is warranted in the Navajo Nation proceeding, and that it will be issuing an order addressing the issues raised by the parties at some point in the future. This order must be entered no later than December 31, 2013, pursuant to the 2005 settlement.

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. Therefore, PNM has elected to participate in this proceeding.  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.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS' fuel cost adjustment clause practices and issues relating to demand cost allocation (the "Golden Spread Proceeding"). In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM ("SPS 2006 Rate Proceeding"). In 2008, FERC issued its order in the Golden Spread Proceeding affirming an ALJ decision that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues that had been ordered by the ALJ.  FERC also reversed the decision of the ALJ, which had been favorable to PNM, on the demand cost allocation issues. PNM and SPS filed petitions for rehearing and clarification of the scope of the remedies that were ordered and seeking reversal of various rulings in the order. On August 15, 2013, FERC issued separate orders in the Golden Spread Proceeding and in the SPS 2006 Rate Proceeding. The order in the Golden Spread Proceeding determined that PNM was not entitled to refunds for SPS' fuel cost adjustment clause practices. That order and the order in the SPS 2006 Rate Proceeding decided the demand cost allocation issues using the method that PNM had advocated.  PNM, SPS, and other customers of SPS have filed requests for rehearing of these orders and they are pending further action by FERC. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes.

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.  PNM continues to participate in this matter in order to preserve its interests regarding any PNM-acquired rights-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time.

In a separate matter, in September 2012, forty-three 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. PNM is participating in this matter in order to preserve its interests regarding the right-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time.

TGP Complaint

On March 2, 2012, TGP Granada, LLC and its affiliate (collectively, "TGP") filed a complaint at FERC against PNM and Tortoise Capital Resources Corp. ("TTO"). PNM owns 60% of the EIP and leases the other 40% from TTO. PNM's lease of the portion of the EIP owned by TTO expires on April 1, 2015. The lease provides PNM the option, with 24 months advance notice, of purchasing the leased assets at the end of the lease for fair market value, as well as options to renew the lease.

TGP's filing requested FERC to direct PNM and TTO to identify the party that will immediately assume the obligation of making transmission capacity on the EIP available to customers for use after the April 1, 2015 expiration of the EIP lease agreement. TGP also requested a declaratory order or waiver regarding certain provisions of PNM's Open Access Transmission Tariff to allow its affiliate to change the point-of-receipt associated with a transmission service agreement related to the EIP without losing its transmission service priority. On July 5, 2012, FERC issued an order denying TGP's requests for declaratory order and waiver. In addition, FERC directed PNM, in consultation with TTO, to identify the party that will provide long-term transmission service over the leased portion of the EIP.

On November 1, 2012, PNM and TTO entered into a definitive agreement for PNM to exercise the option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. The lease remains in existence and PNM will record the purchase at the termination of the lease on April 1, 2015. The definitive agreement sets forth the terms and conditions under which PNM would also assume responsibility for scheduling long-term transmission service on the leased capacity. In November 2012, PNM requested the necessary FERC approvals for the definitive agreement. In January 2013, FERC approved PNM's requests. On February 8, 2013, FERC issued an order dismissing as moot a motion filed by TGP for clarification of FERC's July 5, 2012 order. Since no rehearing request or appeal was filed, the February 8, 2013 order is final and non-appealable.

XML

Goodwill (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012
Goodwill [Line Items]
Goodwill	$ 278,297	$ 278,297	$ 278,297
Public Service Company of New Mexico [Member]
Goodwill [Line Items]
Goodwill	51,632	51,632
Texas-New Mexico Power Company [Member]
Goodwill [Line Items]
Goodwill	$ 226,665	$ 226,665
Minimum [Member] | Public Service Company of New Mexico [Member]
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	10.00%
Minimum [Member] | Texas-New Mexico Power Company [Member]
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	10.00%

XML

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Unrealized holding gains (losses) arising during the period, income tax (expense)	$ (4,143)	$ (4,972)	$ (7,544)	$ (15,409)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	925	4,248	3,639	12,786
Pension liability adjustment, income tax (expense) benefit	(631)	(476)	(1,893)	(1,428)
Change in fair market value, income tax (expense)	128	51	127	150
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	(19)	(16)	(54)	(47)
Public Service Company of New Mexico [Member]
Unrealized holding gains (losses) arising during the period, income tax (expense)	(4,143)	(4,972)	(7,544)	(15,409)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	925	4,248	3,639	12,786
Pension liability adjustment, income tax (expense) benefit	(631)	(476)	(1,893)	(1,428)
Texas-New Mexico Power Company [Member]
Change in fair market value, income tax (expense)	128	51	127	150
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	$ (19)	$ (16)	$ (54)	$ (47)

XML

Segment Information

9 Months Ended

Sep. 30, 2013

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 general 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 excluded from retail rates. FERC has jurisdiction over wholesale 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 PNMR Services Company.

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
Three Months Ended September 30, 2013	(In thousands)
Electric operating revenues	$	326,026		$	73,704		$	—		$	399,730
Cost of energy	100,200			14,474			—			114,674
Margin	225,826			59,230			—			285,056
Other operating expenses	104,730			23,126			(3,282		)	124,574
Depreciation and amortization	25,879			13,850			3,014			42,743
Operating income	95,217			22,254			268			117,739
Interest income	2,298			—			(34		)	2,264
Other income (deductions)	2,211			716			(3,455		)	(528		)
Net interest charges	(20,124		)	(6,655		)	(3,586		)	(30,365		)
Segment earnings (loss) before income taxes	79,602			16,315			(6,807		)	89,110
Income taxes (benefit)	27,652			6,209			(3,565		)	30,296
Segment earnings (loss)	51,950			10,106			(3,242		)	58,814
Valencia non-controlling interest	(4,127		)	—			—			(4,127		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	47,691		$	10,106		$	(3,242	)	$	54,555
Nine Months Ended September 30, 2013
Electric operating revenues	$	863,609		$	201,384		$	—		$	1,064,993
Cost of energy	283,715			41,324			—			325,039
Margin	579,894			160,060			—			739,954
Other operating expenses	311,372			67,274			(10,192		)	368,454
Depreciation and amortization	77,763			37,810			9,616			125,189
Operating income	190,759			54,976			576			246,311
Interest income	7,839			—			(108		)	7,731
Other income (deductions)	6,977			1,409			(7,390		)	996
Net interest charges	(59,971		)	(20,661		)	(11,647		)	(92,279		)
Segment earnings (loss) before income taxes	145,604			35,724			(18,569		)	162,759
Income taxes (benefit)	49,184			13,554			(4,138		)	58,600
Segment earnings (loss)	96,420			22,170			(14,431		)	104,159
Valencia non-controlling interest	(10,904		)	—			—			(10,904		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	85,120		$	22,170		$	(14,431	)	$	92,859
At September 30, 2013:
Total Assets	$	4,192,470		$	1,162,587		$	73,757		$	5,428,814
Goodwill	$	51,632		$	226,665		$	—		$	278,297
Additions to utility and non-utility plant included in accounts payable	$	15,995		$	544		$	1,668		$	18,207

	PNM			TNMP			Corporate and Other			Consolidated
Three Months Ended September 30, 2012	(In thousands)
Electric operating revenues	$	321,731		$	68,680		$	—		$	390,411
Cost of energy	99,217			11,560			—			110,777
Margin	222,514			57,120			—			279,634
Other operating expenses	101,104			22,331			(4,771		)	118,664
Depreciation and amortization	24,437			13,819			4,564			42,820
Operating income	96,973			20,970			207			118,150
Interest income	3,173			—			(43		)	3,130
Other income (deductions)	5,210			366			(827		)	4,749
Net interest charges	(19,230		)	(7,047		)	(4,238		)	(30,515		)
Segment earnings (loss) before income taxes	86,126			14,289			(4,901		)	95,514
Income taxes (benefit)	31,235			5,205			(2,902		)	33,538
Segment earnings (loss)	54,891			9,084			(1,999		)	61,976
Valencia non-controlling interest	(3,980		)	—			—			(3,980		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	50,779		$	9,084		$	(1,999	)	$	57,864
Nine Months Ended September 30, 2012
Electric operating revenues	$	832,242		$	187,404		$	—		$	1,019,646
Cost of energy	263,009			34,333			—			297,342
Margin	569,233			153,071			—			722,304
Other operating expenses	311,468			64,239			(12,676		)	363,031
Depreciation and amortization	72,017			37,173			13,099			122,289
Operating income (loss)	185,748			51,659			(423		)	236,984
Interest income	9,938			1			(131		)	9,808
Other income (deductions)	9,201			1,244			(4,797		)	5,648
Net interest charges	(56,652		)	(21,214		)	(12,414		)	(90,280		)
Segment earnings (loss) before income taxes	148,235			31,690			(17,765		)	162,160
Income taxes (benefit)	51,929			11,577			(8,897		)	54,609
Segment earnings (loss)	96,306			20,113			(8,868		)	107,551
Valencia non-controlling interest	(10,699		)	—			—			(10,699		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	85,211		$	20,113		$	(8,868	)	$	96,456
At September 30, 2012:
Total Assets	$	4,073,331		$	1,060,062		$	126,814		$	5,260,207
Goodwill	$	51,632		$	226,665		$	—		$	278,297
Additions to utility and non-utility plant included in accounts payable	$	6,056		$	886		$	1,063		$	8,005

XML

Significant Accounting Policies and Responsibility for Financial Statements (Policies)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Principles of Consolidation

The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates the PVNGS Capital Trust and Valencia. 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.

PNMR shared services' administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 12.

Segment Reporting

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.

Variable Interest Entity

GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, including determining the primary beneficiary of a variable interest entity, by 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. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity.

XML

Pension and Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2013

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 ("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 2012 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
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	65		$	54		$	—	$	—
Interest cost	7,035			8,058			1,029			1,324			180		219
Expected return on plan assets	(10,482		)	(10,325		)	(1,261		)	(1,225		)	—		—
Amortization of net (gain) loss	3,710			2,629			1,061			972			58		21
Amortization of prior service cost	19			79			(336		)	(336		)	—		—
Net periodic benefit cost	$	282		$	441		$	558		$	789		$	238	$	240
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	195		$	162		$	—	$	—
Interest cost	21,106			24,174			3,085			3,972			540		657
Expected return on plan assets	(31,447		)	(30,975		)	(3,782		)	(3,675		)	—		—
Amortization of net (gain) loss	11,130			7,887			3,182			2,916			174		63
Amortization of prior service cost	57			237			(1,008		)	(1,008		)	—		—
Net periodic benefit cost	$	846		$	1,323		$	1,672		$	2,367		$	714	$	720

PNM made contributions to its pension plan trust of zero and $60.0 million in the three and nine months ended September 30, 2013 and zero and $77.7 million in the three and nine months ended September 30, 2012. PNM does not anticipate making additional contributions to its pension trust in 2013.  Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, PNM estimates minimum required contributions for its pension plan trust would total $49.1 million for 2014-2017. Minimum required contributions were developed using current funding assumptions, including discount rates of 4.8% to 5.2%. Actual amounts required to be funded in the future will depend 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, 2013 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2012. PNM expects contributions during 2013 to the OPEB trust to total $3.3 million.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.1 million in the three and nine months ended September 30, 2013 and $0.4 million and $1.1 million in the three and nine months ended September 30, 2012 and are expected to total $1.5 million during 2013.

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
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	75		$	61		$	—	$	—
Interest cost	772			909			141			156			9		11
Expected return on plan assets	(1,212		)	(1,331		)	(126		)	(129		)	—		—
Amortization of net (gain) loss	262			115			—			(52		)	—		—
Amortization of prior service cost	—			—			14			14			—		—
Net Periodic Benefit Cost (Income)	$	(178	)	$	(307	)	$	104		$	50		$	9	$	11
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	225		$	183		$	—	$	—
Interest cost	2,315			2,727			424			468			27		33
Expected return on plan assets	(3,637		)	(3,993		)	(377		)	(387		)	—		—
Amortization of net (gain) loss	787			345			—			(156		)	—		—
Amortization of prior service cost	—			—			43			42			—		—
Net Periodic Benefit Cost (Income)	$	(535	)	$	(921	)	$	315		$	150		$	27	$	33

TNMP made contributions to its pension plan trust of zero and $1.0 million in the three and nine months ended September 30, 2013 and zero and $5.3 million in the three and nine months ended September 30, 2012. TNMP does not anticipate making additional contributions to its pension trust in 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, TNMP estimates there would be no minimum required contributions to its pension plan trust for 2014-2017. Minimum required contributions were developed using current funding assumptions, including discount rates of 4.8% and 5.2%. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions to the OPEB trust of zero and $0.3 million in the three and nine months ended September 30, 2013 and zero and $0.3 million in the three and nine months ended September 30, 2012. TNMP does not anticipate making additional contributions to the OPEB trust in 2013. 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, 2013 and 2012 and are expected to total $0.1 million during 2013.

XML

Commitments and Contingencies (Other Commitments and Contingencies) (Details) (USD $)									9 Months Ended						9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Public Service Company of New Mexico [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member]	Oct. 31, 2012 Public Service Company of New Mexico [Member]	Sep. 30, 2013 San Juan Generating Station [Member] Public Service Company of New Mexico [Member] Coal Supply [Member]	Dec. 31, 2012 San Juan Generating Station [Member] Public Service Company of New Mexico [Member] Coal Supply [Member]	Sep. 30, 2013 Surface [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 TGP Granada, LLC and its affiliate Complaint [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 TGP Granada, LLC and its affiliate Complaint [Member] Tortoise Capital Resources Corporation [Member]	Sep. 30, 2013 Nuclear Plant [Member] Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Nuclear Plant [Member] Maximum [Member] Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Nuclear Plant [Member] Commercial Providers [Member] Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Nuclear Plant [Member] Industry Wide Retrospective Assessment Program [Member] Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Loss on Long-term Purchase Commitment [Member] Surface [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2012 Loss on Long-term Purchase Commitment [Member] Surface [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Loss on Long-term Purchase Commitment [Member] Surface [Member] San Juan Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Loss on Long-term Purchase Commitment [Member] Underground [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2012 Loss on Long-term Purchase Commitment [Member] Underground [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Loss on Long-term Purchase Commitment [Member] Underground [Member] San Juan Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 San Juan Underground Mine Fire [Member] Fuel and Purchased Power Adjustment Clause [Member] San Juan Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Continuous Highwall Mining [Member] San Juan Generating Station [Member]	Sep. 30, 2013 SJCC Arbitration [Member] San Juan Generating Station [Member]	Sep. 30, 2013 SJCC Arbitration [Member] San Juan Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 NMTRD Coal Severance Tax [Member] Four Corners [Member]	Sep. 30, 2013 NMTRD Coal Severance Tax [Member] Four Corners [Member] Public Service Company of New Mexico [Member]
Public Utilities, Commitments and Contingencies [Line Items]
Other current assets	$ 37,404,000	$ 31,490,000	$ 32,294,000	$ 27,457,000		$ 15,800,000	$ 9,900,000
Final Reclamation, capped amount to be collected															100,000,000
Preliminary estimate increased deferral related to mine fire incident																					21,600,000
Public Utilities, Insurance Recovery																					18,700,000
Public Utilities, Proposed Retroactive Surface Mining Royalty Rate																						12.50%
Public Utilities, Current Surface Mining Royalty Rate applied between 2000 and 2003																						8.00%
Public Utilities, Estimated Underpaid Surface Mining Royalties under proposed rate change																						5,000,000
Public Utilities, PNM Share Estimated Underpaid Surface Mining Royalties under proposed rate change																						46.30%
Public Utilities, SJCC Disputed Mining Costs																							1,500,000.0
Public Utilities, PNM Share of SJCC Disputed Mining Costs																							700,000
Public Utilities, PNM Share of SJCC Disputed Mining Costs to pass through FPPAC																							500,000
Public Utilities, Potential Unbilled Mining Costs Owed to SJCC																							5,200,000.0
Public Utilities, Potential Overbilled Mining Costs SJCC Owes to SJGS Owners																							1,100,000.0
Public Utilities, Potential Capital Improvements billed as Mining Costs to SJGS Owners																							12,900,000.0
Public Utilities, PNM Share of arbitration ruling																								46.30%
Public Utilities, FFPAC Percentage of mining costs overbilled or unbilled ruled by arbitration																								33.00%
Public Utilities, FFPAC Percentage of capital improvements billed as mining costs ruled by arbitration																								25.00%
Public Utilities, Assessed Coal Severance Surtax Penalty and Interest																									30,000,000
Public Utilities, PNM Share Assessed Coal Severance Surtax Penalty and Interest to pass through FFPAC																										8.00%
Public Utilities, Liability Insurance Coverage												13,600,000,000	375,000,000	13,200,000,000
Public Utilities, Ownership Percentage in Nuclear Reactor											10.20%
Public Utilities, Maximum Potential Assessment Per Incident											38,900,000
Public Utilities, Annual Payment Limitation Related to Incident											5,700,000
Public Utilities, Aggregate Amount of All Risk Insurance											2,750,000,000
Public Utilities, Sublimit Amount under Nuclear Electric Insurance Limited											1,500,000,000
Public Utilities, Maximum Amount under Nuclear Electric Insurance Limited											4,300,000
Public Utilities, Lease ownership percentage in EIP									60.00%	40.00%
Public Utilities, Option to Purchase Leased Capacity At Fair Value					7,700,000
Loss Contingency, Estimate of Possible Loss																	56,900,000			19,700,000
Loss Contingency Accrual, at Carrying Value															23,700,000	26,800,000		4,600,000	4,200,000
Regulatory Assets								$ 100,000,000

XML

Fair Value of Derivative and Other Financial Instruments, Statement of Earnings Information (Details) (Commodity Contract [Member], Fair Value Hedging [Member], USD $) In Thousands, unless otherwise specified	9 Months Ended						3 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Electric operating revenues [Member]	Sep. 30, 2012 Electric operating revenues [Member]	Sep. 30, 2013 Cost of energy [Member]	Sep. 30, 2012 Cost of energy [Member]	Sep. 30, 2013 PNMR and PNM [Member]	Sep. 30, 2012 PNMR and PNM [Member]	Sep. 30, 2013 PNMR and PNM [Member] Electric operating revenues [Member]	Sep. 30, 2012 PNMR and PNM [Member] Electric operating revenues [Member]	Sep. 30, 2013 PNMR and PNM [Member] Cost of energy [Member]	Sep. 30, 2012 PNMR and PNM [Member] Cost of energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 6,164	$ 619	$ 5,743	$ 897	$ 421	$ (278)	$ 7,005	$ (477)	$ 7,077	$ (740)	$ (72)	$ 263

XML

Variable Interest Entities (Tables) (Public Service Company of New Mexico [Member])

9 Months Ended

Sep. 30, 2013

Public Service Company of New Mexico [Member]

Variable Interest Entity [Line Items]

Noncontrolling Interest Summarized Financial Information [Table Text Block]

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Operating revenues	$	5,453		$	5,358		$	15,150		$	14,916
Operating expenses	(1,326		)	(1,378		)	(4,246		)	(4,217		)
Earnings attributable to non-controlling interest	$	4,127		$	3,980		$	10,904		$	10,699

Financial Position

	September 30,		December 31,
	2013		2012
	(In thousands)
Current assets	$	3,457	$	3,655
Net property, plant, and equipment	75,841		77,953
Total assets	79,298		81,608
Current liabilities	1,028		765
Owners' equity – non-controlling interest	$	78,270	$	80,843

XML

Accumulated Other Comprehensive Income (Loss) (Tables)

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2013 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	Unrealized						Fair Value
	Gain on			Pension			Adjustment
	Investment			Liability			for Cash Flow
	Securities			Adjustment			Hedges			Total
	(In thousands)
PNMR
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	(216	)	$	(81,630	)
Amounts reclassified from AOCI (pre-tax)	(9,190		)	4,773			153			(4,264		)
Income tax impact of amounts reclassified	3,639			(1,893		)	(54		)	1,692
Other OCI changes (pre-tax)	19,056			—			(363		)	18,693
Income tax impact of other OCI changes	(7,544		)	—			127			(7,417		)
Net change after income taxes	5,961			2,880			(137		)	8,704
Balance at September 30, 2013	$	22,367		$	(94,940	)	$	(353	)	$	(72,926	)

PNM
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	—	$	(81,414	)
Amounts reclassified from AOCI (pre-tax)	(9,190		)	4,773			—		(4,417		)
Income tax impact of amounts reclassified	3,639			(1,893		)	—		1,746
Other OCI changes (pre-tax)	19,056			—			—		19,056
Income tax impact of other OCI changes	(7,544		)	—			—		(7,544		)
Net change after income taxes	5,961			2,880			—		8,841
Balance at September 30, 2013	$	22,367		$	(94,940	)	$	—	$	(72,573	)

TNMP
Balance at December 31, 2012	$	—	$	—	$	(216	)	$	(216	)
Amounts reclassified from AOCI (pre-tax)	—		—		153			153
Income tax impact of amounts reclassified	—		—		(54		)	(54		)
Other OCI changes (pre-tax)	—		—		(363		)	(363		)
Income tax impact of other OCI changes	—		—		127			127
Net change after income taxes	—		—		(137		)	(137		)
Balance at September 30, 2013	$	—	$	—	$	(353	)	$	(353	)

XML

Financing, Financing Activities (Details) (USD $)	9 Months Ended					9 Months Ended						0 Months Ended						9 Months Ended		0 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2013 Public Service Company of New Mexico [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member]	Sep. 30, 2013 Texas-New Mexico Power Company [Member]	Sep. 30, 2012 Texas-New Mexico Power Company [Member]	Mar. 06, 2013 Texas-New Mexico Power Company [Member]	Dec. 31, 2012 Texas-New Mexico Power Company [Member]	Sep. 30, 2013 PNMR Term Loan Agreement [Member]	Dec. 31, 2012 PNMR Term Loan Agreement [Member]	Apr. 03, 2013 First Mortgage Bonds [Member] Texas-New Mexico Power Company [Member]	Apr. 03, 2013 First Mortgage Bonds [Member] First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] Texas-New Mexico Power Company [Member]	Mar. 06, 2013 First Mortgage Bonds [Member] First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] Texas-New Mexico Power Company [Member]	Apr. 03, 2013 First Mortgage Bonds [Member] First Mortgage Bonds, due 2043, Series 2013A [Member] Texas-New Mexico Power Company [Member]	Mar. 06, 2013 First Mortgage Bonds [Member] First Mortgage Bonds, due 2043, Series 2013A [Member] Texas-New Mexico Power Company [Member]	Sep. 30, 2013 Senior Unsecured Note, Due 2015, at 9 point 25 percent [Member]	Sep. 30, 2013 Senior Unsecured Note, Due 2015, at 9 point 25 percent [Member]	Oct. 02, 2013 Subsequent Event [Member] Local Lines of Credit [Member]	Apr. 22, 2013 Notes Payable to Banks [Member] PNM Term Loan Agreement [Member]	Sep. 30, 2013 Notes Payable to Banks [Member] PNM Term Loan Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount								$ 1,000						$ 265,500,000	$ 93,200,000
Debt Instrument, Interest Rate, Stated Percentage													9.50%	9.50%	6.95%	6.95%	9.25%				1.44%
Debt Instrument, Cash Offered for Debt Exchanged								140
Cash paid in debt exchange	(13,048,000)	0				(13,048,000)	0					13,000,000
Debt Instrument, Cash for Bond Exchange Conversion																0.14
Debt Instrument, Unamortized Premium															23,200,000
Short-term debt	112,000,000		158,700,000	0	21,100,000	12,000,000			0	100,000,000	100,000,000									75,000,000
Repayments of Lines of Credit																				75,000,000
Unsecured Long-term Debt, Noncurrent																		23,000,000
Debt Instrument, Cash Paid for Unsecured Debt																		26,000,000
Debt Instruments, NMPRC Approved credit facility																			$ 50,000,000

XML

Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	$ 399,730	$ 390,411	$ 1,064,993	$ 1,019,646
Cost of energy	114,674	110,777	325,039	297,342
Margin	285,056	279,634	739,954	722,304
Other operating expenses	124,574	118,664	368,454	363,031
Depreciation and amortization	42,743	42,820	125,189	122,289
Operating income	117,739	118,150	246,311	236,984
Interest income	2,264	3,130	7,731	9,808
Other income (deductions)	(528)	4,749	996	5,648
Net interest charges	(30,365)	(30,515)	(92,279)	(90,280)
Earnings before Income Taxes	89,110	95,514	162,759	162,160
Income taxes (benefit)	30,296	33,538	58,600	54,609
Net Earnings	58,814	61,976	104,159	107,551
Valencia non-controlling interest	(4,127)	(3,980)	(10,904)	(10,699)
Subsidiary preferred stock dividends	(132)	(132)	(396)	(396)
Net Earnings Attributable to PNMR	54,555	57,864	92,859	96,456
Total Assets	5,428,814	5,260,207	5,428,814	5,260,207	5,372,583
Goodwill	278,297	278,297	278,297	278,297	278,297
Additions to utility and non-utility plant included in accounts payable	18,207	8,005	18,207	8,005
PNM Electric [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	326,026	321,731	863,609	832,242
Cost of energy	100,200	99,217	283,715	263,009
Margin	225,826	222,514	579,894	569,233
Other operating expenses	104,730	101,104	311,372	311,468
Depreciation and amortization	25,879	24,437	77,763	72,017
Operating income	95,217	96,973	190,759	185,748
Interest income	2,298	3,173	7,839	9,938
Other income (deductions)	2,211	5,210	6,977	9,201
Net interest charges	(20,124)	(19,230)	(59,971)	(56,652)
Earnings before Income Taxes	79,602	86,126	145,604	148,235
Income taxes (benefit)	27,652	31,235	49,184	51,929
Net Earnings	51,950	54,891	96,420	96,306
Valencia non-controlling interest	(4,127)	(3,980)	(10,904)	(10,699)
Subsidiary preferred stock dividends	(132)	(132)	(396)	(396)
Net Earnings Attributable to PNMR	47,691	50,779	85,120	85,211
Total Assets	4,192,470	4,073,331	4,192,470	4,073,331
Goodwill	51,632	51,632	51,632	51,632
Additions to utility and non-utility plant included in accounts payable	15,995	6,056	15,995	6,056
TNMP Electric [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	73,704	68,680	201,384	187,404
Cost of energy	14,474	11,560	41,324	34,333
Margin	59,230	57,120	160,060	153,071
Other operating expenses	23,126	22,331	67,274	64,239
Depreciation and amortization	13,850	13,819	37,810	37,173
Operating income	22,254	20,970	54,976	51,659
Interest income	0	0	0	1
Other income (deductions)	716	366	1,409	1,244
Net interest charges	(6,655)	(7,047)	(20,661)	(21,214)
Earnings before Income Taxes	16,315	14,289	35,724	31,690
Income taxes (benefit)	6,209	5,205	13,554	11,577
Net Earnings	10,106	9,084	22,170	20,113
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings Attributable to PNMR	10,106	9,084	22,170	20,113
Total Assets	1,162,587	1,060,062	1,162,587	1,060,062
Goodwill	226,665	226,665	226,665	226,665
Additions to utility and non-utility plant included in accounts payable	544	886	544	886
Corporate and Other [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	0	0	0	0
Cost of energy	0	0	0	0
Margin	0	0	0	0
Other operating expenses	(3,282)	(4,771)	(10,192)	(12,676)
Depreciation and amortization	3,014	4,564	9,616	13,099
Operating income	268	207	576	(423)
Interest income	(34)	(43)	(108)	(131)
Other income (deductions)	(3,455)	(827)	(7,390)	(4,797)
Net interest charges	(3,586)	(4,238)	(11,647)	(12,414)
Earnings before Income Taxes	(6,807)	(4,901)	(18,569)	(17,765)
Income taxes (benefit)	(3,565)	(2,902)	(4,138)	(8,897)
Net Earnings	(3,242)	(1,999)	(14,431)	(8,868)
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings Attributable to PNMR	(3,242)	(1,999)	(14,431)	(8,868)
Total Assets	73,757	126,814	73,757	126,814
Goodwill	0	0	0	0
Additions to utility and non-utility plant included in accounts payable	$ 1,668	$ 1,063	$ 1,668	$ 1,063

XML

Fair Value of Derivative and Other Financial Instruments, Available for Sale Securities (Details) (PNMR and PNM [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			$ 37,020		$ 27,156
Available-for-sale securities, Fair value	211,405		211,405		192,511
Proceeds from sales	103,230	90,518	179,336	136,305
Gross realized gains	2,611	6,263	8,962	11,029
Gross realized (losses)	(1,202)	(5,131)	(2,920)	(7,055)
Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			0		0
Available-for-sale securities, Fair value	24,414		24,414		4,628
Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			10,519		5,223
Available-for-sale securities, Fair value	34,967		34,967		30,044
Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			23,355		15,212
Available-for-sale securities, Fair value	67,527		67,527		51,650
International and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			1,543		247
Available-for-sale securities, Fair value	16,159		16,159		14,868
U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			262		1,305
Available-for-sale securities, Fair value	16,711		16,711		32,592
Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			1,120		4,069
Available-for-sale securities, Fair value	37,074		37,074		43,861
Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			221		1,100
Available-for-sale securities, Fair value	$ 14,553		$ 14,553		$ 14,868

XML

Pension and Other Postretirement Benefit Plans (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$ 0	$ 0	$ 0	$ 0
Interest cost	7,035,000	8,058,000	21,106,000	24,174,000
Long-term return on plan assets	(10,482,000)	(10,325,000)	(31,447,000)	(30,975,000)
Amortization of net loss	3,710,000	2,629,000	11,130,000	7,887,000
Amortization of prior service cost	19,000	79,000	57,000	237,000
Net periodic benefit cost	282,000	441,000	846,000	1,323,000
Defined Benefit Plan, Contributions by Employer	0	0	60,000,000	77,700,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	49,100,000		49,100,000
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)			4.80%
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)			5.20%
Public Service Company of New Mexico [Member] | OPEB [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	65,000	54,000	195,000	162,000
Interest cost	1,029,000	1,324,000	3,085,000	3,972,000
Long-term return on plan assets	(1,261,000)	(1,225,000)	(3,782,000)	(3,675,000)
Amortization of net loss	1,061,000	972,000	3,182,000	2,916,000
Amortization of prior service cost	(336,000)	(336,000)	(1,008,000)	(1,008,000)
Net periodic benefit cost	558,000	789,000	1,672,000	2,367,000
Defined Benefit Plan, Contributions by Employer	800,000	800,000	2,400,000	2,400,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	3,300,000		3,300,000
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	180,000	219,000	540,000	657,000
Long-term return on plan assets	0	0	0	0
Amortization of net loss	58,000	21,000	174,000	63,000
Amortization of prior service cost	0	0	0	0
Net periodic benefit cost	238,000	240,000	714,000	720,000
Defined Benefit Plan, Contributions by Employer	400,000	400,000	1,100,000	1,100,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	1,500,000		1,500,000
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	772,000	909,000	2,315,000	2,727,000
Long-term return on plan assets	(1,212,000)	(1,331,000)	(3,637,000)	(3,993,000)
Amortization of net loss	262,000	115,000	787,000	345,000
Amortization of prior service cost	0	0	0	0
Net periodic benefit cost	(178,000)	(307,000)	(535,000)	(921,000)
Defined Benefit Plan, Contributions by Employer	0		1,000,000	5,300,000
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)	4.80%
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)	5.20%
Texas-New Mexico Power Company [Member] | OPEB [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	75,000	61,000	225,000	183,000
Interest cost	141,000	156,000	424,000	468,000
Long-term return on plan assets	(126,000)	(129,000)	(377,000)	(387,000)
Amortization of net loss	0	(52,000)	0	(156,000)
Amortization of prior service cost	14,000	14,000	43,000	42,000
Net periodic benefit cost	104,000	50,000	315,000	150,000
Defined Benefit Plan, Contributions by Employer	0	0	300,000	300,000
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	9,000	11,000	27,000	33,000
Long-term return on plan assets	0	0	0	0
Amortization of net loss	0	0	0	0
Amortization of prior service cost	0	0	0	0
Net periodic benefit cost	9,000	11,000	27,000	33,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	100,000		100,000
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Contributions by Employer	$ 100,000	$ 100,000	$ 100,000	$ 100,000

XML

Financing (Tables)

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Schedule of Short-term Debt [Table Text Block]

hort-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2013		2012
	(In thousands)
PNM – Revolving credit facility	$	—	$	21,100
TNMP – Revolving credit facility	12,000		—
PNMR:
Revolving credit facility	—		37,600
PNMR Term Loan Agreement	100,000		100,000
	$	112,000	$	158,700

XML

Earnings Per Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Earnings Per Share [Abstract]
Net Earnings Attributable to PNMR	$ 54,555		$ 57,864		$ 92,859		$ 96,456
Average Number of Common Shares:
Outstanding during period	79,654,000		79,654,000		79,654,000		79,654,000
Vested awards of restricted stock	177,000		114,000		194,000		156,000
Average Shares - Basic	79,831,000		79,768,000		79,848,000		79,810,000
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	503,000	[1]	622,000	[1]	608,000	[1]	600,000	[1]
Average Shares - Diluted	80,334,000		80,390,000		80,456,000		80,410,000
Net Earnings Per Share of Common Stock
Basic (dollars per share)	$ 0.68		$ 0.73		$ 1.16		$ 1.21
Diluted (dollars per share)	$ 0.68		$ 0.72		$ 1.15		$ 1.20
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares)					793,010

[1] Excludes the effect of out-of-the-money options for 793,010 shares of common stock at September 30, 2013.

XML

Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

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
Three Months Ended September 30, 2013	(In thousands)
Electric operating revenues	$	326,026		$	73,704		$	—		$	399,730
Cost of energy	100,200			14,474			—			114,674
Margin	225,826			59,230			—			285,056
Other operating expenses	104,730			23,126			(3,282		)	124,574
Depreciation and amortization	25,879			13,850			3,014			42,743
Operating income	95,217			22,254			268			117,739
Interest income	2,298			—			(34		)	2,264
Other income (deductions)	2,211			716			(3,455		)	(528		)
Net interest charges	(20,124		)	(6,655		)	(3,586		)	(30,365		)
Segment earnings (loss) before income taxes	79,602			16,315			(6,807		)	89,110
Income taxes (benefit)	27,652			6,209			(3,565		)	30,296
Segment earnings (loss)	51,950			10,106			(3,242		)	58,814
Valencia non-controlling interest	(4,127		)	—			—			(4,127		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	47,691		$	10,106		$	(3,242	)	$	54,555
Nine Months Ended September 30, 2013
Electric operating revenues	$	863,609		$	201,384		$	—		$	1,064,993
Cost of energy	283,715			41,324			—			325,039
Margin	579,894			160,060			—			739,954
Other operating expenses	311,372			67,274			(10,192		)	368,454
Depreciation and amortization	77,763			37,810			9,616			125,189
Operating income	190,759			54,976			576			246,311
Interest income	7,839			—			(108		)	7,731
Other income (deductions)	6,977			1,409			(7,390		)	996
Net interest charges	(59,971		)	(20,661		)	(11,647		)	(92,279		)
Segment earnings (loss) before income taxes	145,604			35,724			(18,569		)	162,759
Income taxes (benefit)	49,184			13,554			(4,138		)	58,600
Segment earnings (loss)	96,420			22,170			(14,431		)	104,159
Valencia non-controlling interest	(10,904		)	—			—			(10,904		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	85,120		$	22,170		$	(14,431	)	$	92,859
At September 30, 2013:
Total Assets	$	4,192,470		$	1,162,587		$	73,757		$	5,428,814
Goodwill	$	51,632		$	226,665		$	—		$	278,297
Additions to utility and non-utility plant included in accounts payable	$	15,995		$	544		$	1,668		$	18,207

	PNM			TNMP			Corporate and Other			Consolidated
Three Months Ended September 30, 2012	(In thousands)
Electric operating revenues	$	321,731		$	68,680		$	—		$	390,411
Cost of energy	99,217			11,560			—			110,777
Margin	222,514			57,120			—			279,634
Other operating expenses	101,104			22,331			(4,771		)	118,664
Depreciation and amortization	24,437			13,819			4,564			42,820
Operating income	96,973			20,970			207			118,150
Interest income	3,173			—			(43		)	3,130
Other income (deductions)	5,210			366			(827		)	4,749
Net interest charges	(19,230		)	(7,047		)	(4,238		)	(30,515		)
Segment earnings (loss) before income taxes	86,126			14,289			(4,901		)	95,514
Income taxes (benefit)	31,235			5,205			(2,902		)	33,538
Segment earnings (loss)	54,891			9,084			(1,999		)	61,976
Valencia non-controlling interest	(3,980		)	—			—			(3,980		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	50,779		$	9,084		$	(1,999	)	$	57,864
Nine Months Ended September 30, 2012
Electric operating revenues	$	832,242		$	187,404		$	—		$	1,019,646
Cost of energy	263,009			34,333			—			297,342
Margin	569,233			153,071			—			722,304
Other operating expenses	311,468			64,239			(12,676		)	363,031
Depreciation and amortization	72,017			37,173			13,099			122,289
Operating income (loss)	185,748			51,659			(423		)	236,984
Interest income	9,938			1			(131		)	9,808
Other income (deductions)	9,201			1,244			(4,797		)	5,648
Net interest charges	(56,652		)	(21,214		)	(12,414		)	(90,280		)
Segment earnings (loss) before income taxes	148,235			31,690			(17,765		)	162,160
Income taxes (benefit)	51,929			11,577			(8,897		)	54,609
Segment earnings (loss)	96,306			20,113			(8,868		)	107,551
Valencia non-controlling interest	(10,699		)	—			—			(10,699		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	85,211		$	20,113		$	(8,868	)	$	96,456
At September 30, 2012:
Total Assets	$	4,073,331		$	1,060,062		$	126,814		$	5,260,207
Goodwill	$	51,632		$	226,665		$	—		$	278,297
Additions to utility and non-utility plant included in accounts payable	$	6,056		$	886		$	1,063		$	8,005

XML

Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current Assets:
Cash and cash equivalents	$ 33,439	$ 8,985
Accounts receivable, net of allowance for uncollectible accounts of $1,391 and $1,751 for PNMR and PNM	110,937	87,093
Unbilled revenues	55,155	57,266
Other receivables	53,681	53,332
Materials, supplies, and fuel stock	60,367	59,643
Regulatory assets	38,511	39,120
Commodity derivative instruments	5,743	3,785
Income taxes receivable	5,283	101,477
Other current assets	37,404	31,490
Total current assets	400,520	442,191
Other Property and Investments:
Investment in PVNGS lessor notes	32,542	54,325
Investments held by NDT	207,483	188,971
Other investments	6,725	9,139
Non-utility property, net of accumulated depreciation of $143 and $131 for PNMR	4,475	4,487
Total other property and investments	251,225	256,922
Utility Plant:
Plant in service and plant held for future use	5,431,680	5,313,796
Less accumulated depreciation and amortization	1,839,481	1,774,223
Net plant in service and plant held for future use	3,592,199	3,539,573
Construction work in progress	175,410	125,287
Nuclear fuel, net of accumulated amortization of $52,876 and $42,644 for PNMR and PNM	79,458	81,627
Net utility plant	3,847,067	3,746,487
Deferred Charges and Other Assets:
Regulatory assets	551,607	555,577
Goodwill	278,297	278,297
Commodity derivative instruments	4,284	352
Other deferred charges	95,814	92,757
Total deferred charges and other assets	930,002	926,983
Assets	5,428,814	5,372,583
Current Liabilities:
Short-term debt	112,000	158,700
Current installments of long-term debt	52,530	2,530
Accounts payable	76,309	99,177
Customer deposits	14,171	18,176
Accrued interest and taxes	82,801	52,003
Regulatory liabilities	1,218	15,173
Commodity derivative instruments	1,017	1,000
Dividends declared	13,271	11,679
Current portion of accumulated deferred income taxes	258	258
Other current liabilities	62,018	75,407
Total current liabilities	415,593	434,103
Long-term Debt	1,696,311	1,669,760
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	743,828	701,545
Accumulated deferred investment tax credits	12,598	14,242
Regulatory liabilities	456,634	423,460
Asset retirement obligations	93,519	85,893
Accrued pension liability and postretirement benefit cost	147,442	224,565
Commodity derivative instruments	1,347	1,933
Other deferred credits	106,554	116,523
Total deferred credits and other liabilities	1,561,922	1,568,161
Total liabilities	3,673,826	3,672,024
Commitments and Contingencies (See Note 10)
Cumulative preferred stock of subsidiary without mandatory redemption requirements ($100 stated value, 10,000,000 shares authorized: issued and outstanding 115,293 shares)	11,529	11,529
Company common stockholders’ equity:
Common Stock, Value, Issued	1,177,686	1,182,819
Accumulated other comprehensive income (loss), net of income taxes	(72,926)	(81,630)
Retained earnings	560,429	506,998
Total Company common stockholders' equity	1,665,189	1,608,187
Non-controlling interest in Valencia	78,270	80,843
Total equity	1,743,459	1,689,030
Total liabilities and stockholders' equity	5,428,814	5,372,583
Public Service Company of New Mexico [Member]
Current Assets:
Cash and cash equivalents	22,179	3,958
Accounts receivable, net of allowance for uncollectible accounts of $1,391 and $1,751 for PNMR and PNM	84,613	69,876
Unbilled revenues	46,473	49,085
Other receivables	52,328	50,975
Affiliate receivables	8,827	9,050
Materials, supplies, and fuel stock	57,534	56,790
Regulatory assets	34,315	36,490
Commodity derivative instruments	5,743	3,785
Income taxes receivable	35,910	80,223
Other current assets	32,294	27,457
Total current assets	380,216	387,689
Other Property and Investments:
Investment in PVNGS lessor notes	32,542	54,325
Investments held by NDT	207,483	188,971
Other investments	4,380	4,034
Non-utility property, net of accumulated depreciation of $143 and $131 for PNMR	976	976
Total other property and investments	245,381	248,306
Utility Plant:
Plant in service and plant held for future use	4,217,120	4,133,532
Less accumulated depreciation and amortization	1,409,042	1,355,240
Net plant in service and plant held for future use	2,808,078	2,778,292
Construction work in progress	136,679	102,329
Nuclear fuel, net of accumulated amortization of $52,876 and $42,644 for PNMR and PNM	79,458	81,627
Net utility plant	3,024,215	2,962,248
Deferred Charges and Other Assets:
Regulatory assets	402,040	431,956
Goodwill	51,632	51,632
Commodity derivative instruments	4,284	352
Other deferred charges	84,702	81,724
Total deferred charges and other assets	542,658	565,664
Assets	4,192,470	4,163,907
Current Liabilities:
Short-term debt	0	21,100
Accounts payable	60,049	73,914
Customer deposits	14,171	18,176
Affiliate payables	13,462	25,340
Accrued interest and taxes	52,735	30,320
Regulatory liabilities	1,218	15,172
Commodity derivative instruments	1,017	1,000
Dividends declared	132	132
Current portion of accumulated deferred income taxes	3,447	3,447
Other current liabilities	40,041	54,150
Total current liabilities	186,272	242,751
Long-term Debt	1,290,608	1,215,579
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	608,366	573,881
Accumulated deferred investment tax credits	12,598	14,242
Regulatory liabilities	409,444	379,841
Asset retirement obligations	92,614	85,042
Accrued pension liability and postretirement benefit cost	134,009	208,618
Commodity derivative instruments	1,347	1,933
Other deferred credits	87,417	95,585
Total deferred credits and other liabilities	1,345,795	1,359,142
Total liabilities	2,822,675	2,817,472
Commitments and Contingencies (See Note 10)
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements	11,529	11,529
Company common stockholders’ equity:
Common Stock, Value, Issued	1,061,776	1,061,776
Accumulated other comprehensive income (loss), net of income taxes	(72,573)	(81,414)
Retained earnings	290,793	273,701
Total Company common stockholders' equity	1,279,996	1,254,063
Non-controlling interest in Valencia	78,270	80,843
Total equity	1,358,266	1,334,906
Total liabilities and stockholders' equity	4,192,470	4,163,907
Texas-New Mexico Power Company [Member]
Current Assets:
Cash and cash equivalents	156	1
Accounts receivable, net of allowance for uncollectible accounts of $1,391 and $1,751 for PNMR and PNM	26,324	17,217
Unbilled revenues	8,682	8,181
Other receivables	1,728	2,359
Materials, supplies, and fuel stock	2,833	2,853
Regulatory assets	4,196	2,630
Current portion of accumulated deferred income taxes	1,131	1,131
Other current assets	1,816	1,107
Total current assets	46,866	35,479
Other Property and Investments:
Other investments	281	281
Non-utility property, net of accumulated depreciation of $143 and $131 for PNMR	2,240	2,240
Total other property and investments	2,521	2,521
Utility Plant:
Plant in service and plant held for future use	1,048,474	1,009,108
Less accumulated depreciation and amortization	347,228	339,315
Net plant in service and plant held for future use	701,246	669,793
Construction work in progress	27,112	19,801
Net utility plant	728,358	689,594
Deferred Charges and Other Assets:
Regulatory assets	149,567	123,621
Goodwill	226,665	226,665
Other deferred charges	8,610	8,349
Total deferred charges and other assets	384,842	358,635
Assets	1,162,587	1,086,229
Current Liabilities:
Short-term debt – affiliate	33,100	28,300
Short-term debt	12,000	0
Current installments of long-term debt	50,000	0
Accounts payable	7,114	8,848
Affiliate payables	2,138	4,381
Accrued interest and taxes	45,160	30,491
Other current liabilities	9,614	8,854
Total current liabilities	159,126	80,874
Long-term Debt	286,128	311,589
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	167,674	163,710
Regulatory liabilities	46,754	43,619
Asset retirement obligations	778	732
Accrued pension liability and postretirement benefit cost	13,433	15,947
Other deferred credits	6,573	5,944
Total deferred credits and other liabilities	235,212	229,952
Total liabilities	680,466	622,415
Commitments and Contingencies (See Note 10)
Company common stockholders’ equity:
Common Stock, Value, Issued	64	64
Paid-in-capital	390,366	390,366
Accumulated other comprehensive income (loss), net of income taxes	(353)	(216)
Retained earnings	92,044	73,600
Total Company common stockholders' equity	482,121	463,814
Total liabilities and stockholders' equity	$ 1,162,587	$ 1,086,229

XML

Condensed Consolidated Statements of Changes in Equity (USD $) In Thousands, unless otherwise specified	Total	Common Stock [Member]	AOCI [Member]	Retained Earnings [Member]	Total Company Common Stockholders' Equity [Member]	Non-controlling Interest in Valencia [Member]	Public Service Company of New Mexico [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] Total Company Common Stockholders' Equity [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] Additional Paid-in Capital [Member]	Texas-New Mexico Power Company [Member] AOCI [Member]	Texas-New Mexico Power Company [Member] Retained Earnings [Member]
Balance at Dec. 31, 2012	$ 1,689,030	$ 1,182,819	$ (81,630)	$ 506,998	$ 1,608,187	$ 80,843	$ 1,334,906	$ 1,061,776	$ (81,414)	$ 273,701	$ 1,254,063	$ 80,843
Balance TNMP at Dec. 31, 2012	1,608,187						1,254,063						463,814	64	390,366	(216)	73,600
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from stock option exercise	3,500	3,500	0	0	3,500	0
Awards of common stock	(12,429)	(12,429)	0	0	(12,429)	0
Excess tax (shortfall) from stock-based payment arrangements	(519)	(519)	0	0	(519)	0
Stock based compensation expense	4,315	4,315	0	0	4,315	0
Valencia's transactions with its owner	(13,477)	0	0	0	0	(13,477)	(13,477)	0	0	0	0	(13,477)
Net Earnings	92,859						85,516						22,170	0	0	0	22,170
Net earnings before subsidiary preferred stock dividends	104,159	0	0	93,255	93,255	10,904	96,420	0	0	85,516	85,516	10,904
Subsidiary preferred stock dividends	(396)	0	0	(396)	(396)	0
Total other comprehensive income (loss)	8,704	0	8,704	0	8,704	0	8,841	0	8,841	0	8,841	0	(137)	0	0	(137)	0
Dividends declared on preferred stock							(396)	0	0	(396)	(396)	0
Dividends declared on common stock	(39,428)	0	0	(39,428)	(39,428)	0	(68,028)	0	0	(68,028)	(68,028)	0	(3,726)	0	0	0	(3,726)
Balance TNMP at Sep. 30, 2013	1,665,189						1,279,996						482,121	64	390,366	(353)	92,044
Balance at Sep. 30, 2013	1,743,459	1,177,686	(72,926)	560,429	1,665,189	78,270	1,358,266	1,061,776	(72,573)	290,793	1,279,996	78,270
Balance at Jun. 30, 2013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Earnings	54,555						47,823						10,106
Net earnings before subsidiary preferred stock dividends	58,814						51,950
Subsidiary preferred stock dividends	(132)
Total other comprehensive income (loss)	5,668						5,871						(203)
Balance TNMP at Sep. 30, 2013	1,665,189						1,279,996						482,121
Balance at Sep. 30, 2013	$ 1,743,459						$ 1,358,266

XML

Accumulated Other Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2013

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, 2013 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	Unrealized						Fair Value
	Gain on			Pension			Adjustment
	Investment			Liability			for Cash Flow
	Securities			Adjustment			Hedges			Total
	(In thousands)
PNMR
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	(216	)	$	(81,630	)
Amounts reclassified from AOCI (pre-tax)	(9,190		)	4,773			153			(4,264		)
Income tax impact of amounts reclassified	3,639			(1,893		)	(54		)	1,692
Other OCI changes (pre-tax)	19,056			—			(363		)	18,693
Income tax impact of other OCI changes	(7,544		)	—			127			(7,417		)
Net change after income taxes	5,961			2,880			(137		)	8,704
Balance at September 30, 2013	$	22,367		$	(94,940	)	$	(353	)	$	(72,926	)

PNM
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	—	$	(81,414	)
Amounts reclassified from AOCI (pre-tax)	(9,190		)	4,773			—		(4,417		)
Income tax impact of amounts reclassified	3,639			(1,893		)	—		1,746
Other OCI changes (pre-tax)	19,056			—			—		19,056
Income tax impact of other OCI changes	(7,544		)	—			—		(7,544		)
Net change after income taxes	5,961			2,880			—		8,841
Balance at September 30, 2013	$	22,367		$	(94,940	)	$	—	$	(72,573	)

TNMP
Balance at December 31, 2012	$	—	$	—	$	(216	)	$	(216	)
Amounts reclassified from AOCI (pre-tax)	—		—		153			153
Income tax impact of amounts reclassified	—		—		(54		)	(54		)
Other OCI changes (pre-tax)	—		—		(363		)	(363		)
Income tax impact of other OCI changes	—		—		127			127
Net change after income taxes	—		—		(137		)	(137		)
Balance at September 30, 2013	$	—	$	—	$	(353	)	$	(353	)

Pre-tax amounts reclassified from AOCI related to "Unrealized Gain on Investment Securities" are included in "Gains on investments held by NDT" 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. Approximately 19.6% of the amount reclassified is then capitalized into construction work in process and approximately 1.1% is 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 is then capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in "Income Taxes" in the Condensed Consolidated Statements of Earnings.

XML

Significant Accounting Policies and Responsibility for Financial Statements

9 Months Ended

Sep. 30, 2013

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, 2013 and December 31, 2012, the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2013 and 2012, and the consolidated cash flows for the nine months ended September 30, 2013 and 2012. 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 2012 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2013 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 2012 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 the PVNGS Capital Trust and Valencia. 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.

PNMR shared services' administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 12.

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 $0.165 per share in July 2013 and $0.145 in July 2012, 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 $0.165 per share in September 2013 and $0.145 in September 2012, which are reflected as being in the third quarter within "Dividends Declared per Common Share" on the PNMR Condensed Consolidated Statements of Earnings.

PNM declared and paid cash dividends on its common stock to PNMR of $68.0 million in the nine months ended September 30, 2013. PNM declared a cash dividend on its common stock to PNMR of $16.8 million in September 2012, which was paid in October 2012, and declared and paid a dividend of $17.7 million in June 2012. TNMP declared and paid cash dividends to PNMR of $3.7 million and $11.0 million in the nine months ended September 30, 2013 and 2012. TNMP dividends paid in 2012 were recorded as reductions of paid-in-capital.

New Accounting Pronouncements

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

Accounting Standards Update 2013-11 - Income Taxes: Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

The FASB released guidance that requires entities to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for net operating losses in certain circumstances. The guidance is to be applied prospectively and is effective for annual and interim reporting periods beginning after December 15, 2013, with early adoption permitted. The Company is still analyzing the impacts of this new standard and when to adopt it. However, it appears that the new standard will result in substantially all of the Company's liability for unrecognized tax benefits being reclassified from being reflected in liability accounts to being reflected as reductions of deferred tax assets. Adoption of this standard is not expected to impact earnings.

XML

Fair Value of Derivative and Other Financial Instruments, Debt Maturities (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013
PNM Resources [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Held-to-maturity debt securities, Due within 1 year	$ 4,840
Held-to-maturity debt securities, After 1 year through 5 years	55,310
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	60,150
Public Service Company of New Mexico [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Held-to-maturity debt securities, Due within 1 year	1,138
Held-to-maturity debt securities, After 1 year through 5 years	53,956
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	55,094
PNMR and PNM [Member]
Available-for-sale Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Available-for-sale debt securities, Within 1 year	1,284
Available-for-sale debt securities, After 1 year through 5 years	16,768
Available-for-sale debt securities, After 5 years through 10 years	8,027
Available-for-sale debt securities, After 10 years through 15 years	3,277
Available-for-sale debt securities, After 15 years through 20 years	5,512
Available-for-sale debt securities, After 20 years	33,470
Available-for-sale debt securities	$ 68,338

XML

Fair Value of Derivative and Other Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value of Derivative and Other Financial Instruments [Line Items]

Fair Value, by Balance Sheet Grouping [Table Text Block]

The carrying amounts and fair values of investments in 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, 2013	(In thousands)
PNMR
Long-term debt	$	1,748,841	$	1,929,828	$	—	$	1,926,126	$	3,702
Investment in PVNGS lessor notes	$	53,300	$	55,094	$	—	$	—	$	55,094
Other investments	$	2,803	$	6,941	$	739	$	—	$	6,202
PNM
Long-term debt	$	1,290,608	$	1,400,109	$	—	$	1,400,109	$	—
Investment in PVNGS lessor notes	$	53,300	$	55,094	$	—	$	—	$	55,094
Other investments	$	458	$	458	$	458	$	—	$	—
TNMP
Long-term debt	$	336,128	$	393,122	$	—	$	393,122	$	—
Other investments	$	281	$	281	$	281	$	—	$	—
December 31, 2012
PNMR
Long-term debt	$	1,672,290	$	1,969,362	$	—	$	1,966,725	$	2,637
Investment in PVNGS lessor notes	$	77,682	$	84,198	$	—	$	—	$	84,198
Other investments	$	5,599	$	6,965	$	774	$	—	$	6,191
PNM
Long-term debt	$	1,215,579	$	1,385,433	$	—	$	1,385,433	$	—
Investment in PVNGS lessor notes	$	77,682	$	84,198	$	—	$	—	$	84,198
Other investments	$	494	$	494	$	494	$	—	$	—
TNMP
Long-term debt	$	311,589	$	418,166	$	—	$	418,166	$	—
Other investments	$	281	$	281	$	281	$	—	$	—

PNMR and PNM [Member]

Fair Value of Derivative and Other Financial Instruments [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

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, 2013			December 31, 2012
PNMR and PNM	(In thousands)
Current assets	$	5,743		$	3,785
Deferred charges	4,284			352
	10,027			4,137
Current liabilities	(1,017		)	(1,000		)
Long-term liabilities	(1,347		)	(1,933		)
	(2,364		)	(2,933		)
Net	$	7,663		$	1,204

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]

The following table presents the effect on earnings, excluding income tax effects and settlements, of commodity derivative instruments that are recorded at fair value. Commodity derivatives had no impact on OCI for the periods presented.

	Economic Hedges
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013		2012
PNMR and PNM	(In thousands)
Electric operating revenues	$	7,077		$	(740	)	$	5,743	$	897
Cost of energy	(72		)	263			421		(278		)
Total gain (loss)	$	7,005		$	(477	)	$	6,164	$	619

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

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
September 30, 2013
PNMR and PNM	980,000	(3,801,738	)
December 31, 2012
PNMR and PNM	1,127,500	(2,477,520	)

Schedule of Collateral Related to Derivative [Table Text Block]

Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and 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)
September 30, 2013
PNMR and PNM	$	2,250	$	—	$	2,224
December 31, 2012
PNMR and PNM	$	2,933	$	—	$	2,777

Available-for-sale Securities [Table Text Block]

The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	September 30, 2013				December 31, 2012
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Cash and cash equivalents	$	—	$	24,414	$	—	$	4,628
Equity securities:
Domestic value	10,519		34,967		5,223		30,044
Domestic growth	23,355		67,527		15,212		51,650
International and other	1,543		16,159		247		14,868
Fixed income securities:
U.S. Government	262		16,711		1,305		32,592
Municipals	1,120		37,074		4,069		43,861
Corporate and other	221		14,553		1,100		14,868
	$	37,020	$	211,405	$	27,156	$	192,511

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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In thousands)
Proceeds from sales	$	103,230		$	90,518		$	179,336		$	136,305
Gross realized gains	$	2,611		$	6,263		$	8,962		$	11,029
Gross realized (losses)	$	(1,202	)	$	(5,131	)	$	(2,920	)	$	(7,055	)

Investments Classified by Contractual Maturity Date [Table Text Block]

At September 30, 2013, 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		PNM
	(In thousands)
Within 1 year	$	1,284	$	4,840	$	1,138
After 1 year through 5 years	16,768		55,310		53,956
After 5 years through 10 years	8,027		—		—
After 10 years through 15 years	3,277		—		—
After 15 years through 20 years	5,512		—		—
After 20 years	33,470		—		—
	$	68,338	$	60,150	$	55,094

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Table Text Block]

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2013	(In thousands)
PNMR and PNM
Decommissioning and reclamation investments:
Cash and cash equivalents	$	24,414		$	24,414	$	—
Equity securities:
Domestic value	34,967			34,967		—
Domestic growth	67,527			67,527		—
International and other	16,159			16,159		—
Fixed income securities:
U.S. government	16,711			14,949		1,762
Municipals	37,074			—		37,074
Corporate and other	14,553			—		14,553
	$	211,405		$	158,016	$	53,389
Commodity derivative assets	$	10,027		$	—	$	10,027
Commodity derivative liabilities	(2,364		)	—		(2,364		)
Net	$	7,663		$	—	$	7,663
December 31, 2012
PNMR and PNM
Decommissioning and reclamation investments:
Cash and cash equivalents	$	4,628		$	4,628	$	—
Equity securities:
Domestic value	30,044			30,044		—
Domestic growth	51,650			51,650		—
International and other	14,868			14,868		—
Fixed income securities:
U.S. government	32,592			27,737		4,855
Municipals	43,861			—		43,861
Corporate and other	14,868			—		14,868
	$	192,511		$	128,927	$	63,584
Commodity derivative assets	$	4,137		$	—	$	4,137
Commodity derivative liabilities	(2,933		)	—		(2,933		)
Net	$	1,204		$	—	$	1,204

XML

Pension and Other Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2013

Public Service Company of New Mexico [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

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
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	65		$	54		$	—	$	—
Interest cost	7,035			8,058			1,029			1,324			180		219
Expected return on plan assets	(10,482		)	(10,325		)	(1,261		)	(1,225		)	—		—
Amortization of net (gain) loss	3,710			2,629			1,061			972			58		21
Amortization of prior service cost	19			79			(336		)	(336		)	—		—
Net periodic benefit cost	$	282		$	441		$	558		$	789		$	238	$	240
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	195		$	162		$	—	$	—
Interest cost	21,106			24,174			3,085			3,972			540		657
Expected return on plan assets	(31,447		)	(30,975		)	(3,782		)	(3,675		)	—		—
Amortization of net (gain) loss	11,130			7,887			3,182			2,916			174		63
Amortization of prior service cost	57			237			(1,008		)	(1,008		)	—		—
Net periodic benefit cost	$	846		$	1,323		$	1,672		$	2,367		$	714	$	720

Texas-New Mexico Power Company [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

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
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	75		$	61		$	—	$	—
Interest cost	772			909			141			156			9		11
Expected return on plan assets	(1,212		)	(1,331		)	(126		)	(129		)	—		—
Amortization of net (gain) loss	262			115			—			(52		)	—		—
Amortization of prior service cost	—			—			14			14			—		—
Net Periodic Benefit Cost (Income)	$	(178	)	$	(307	)	$	104		$	50		$	9	$	11
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2013			2012			2013			2012			2013		2012
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	225		$	183		$	—	$	—
Interest cost	2,315			2,727			424			468			27		33
Expected return on plan assets	(3,637		)	(3,993		)	(377		)	(387		)	—		—
Amortization of net (gain) loss	787			345			—			(156		)	—		—
Amortization of prior service cost	—			—			43			42			—		—
Net Periodic Benefit Cost (Income)	$	(535	)	$	(921	)	$	315		$	150		$	27	$	33

XML

Fair Value of Derivative and Other Financial Instruments, Derivative Balance Sheet Information (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Assets, Current	$ 400,520,000	$ 442,191,000
Liabilities, Current	415,593,000	434,103,000
Commodity derivative instruments, Current assets	5,743,000	3,785,000
Commodity derivative instruments, Deferred charges	4,284,000	352,000
Commodity derivative instruments, Current liabilities	(1,017,000)	(1,000,000)
Commodity derivative instruments, Long-term liabilities	(1,347,000)	(1,933,000)
PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Margin Deposit Assets	2,000,000	1,900,000
Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Assets, Current	380,216,000	387,689,000
Liabilities, Current	186,272,000	242,751,000
Commodity derivative instruments, Current assets	5,743,000	3,785,000
Commodity derivative instruments, Deferred charges	4,284,000	352,000
Commodity derivative instruments, Current liabilities	(1,017,000)	(1,000,000)
Commodity derivative instruments, Long-term liabilities	(1,347,000)	(1,933,000)
Commodity Contract [Member] | Fair Value Hedging [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	5,743,000	3,785,000
Commodity derivative instruments, Deferred charges	4,284,000	352,000
Commodity derivative instruments, Assets	10,027,000	4,137,000
Commodity derivative instruments, Current liabilities	(1,017,000)	(1,000,000)
Commodity derivative instruments, Long-term liabilities	(1,347,000)	(1,933,000)
Commodity derivative instruments, Liabilities	(2,364,000)	(2,933,000)
Commodity derivative instruments, Net	7,663,000	1,204,000
Commodity Contract [Member] | Fuel and Purchased Power Adjustment Clause [Member] | Fair Value Hedging [Member] | Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Assets, Current	600,000	100,000
Assets, Noncurrent	100,000
Liabilities, Current	100,000
Palo Verde Nuclear Generating Station [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	2,300,000
Commodity derivative instruments, Deferred charges	$ 3,800,000
Palo Verde Nuclear Generating Station [Member] | Firm Contract [Member] | Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Percentage of Electric Power Plant Output Sold through 2013	100.00%

XML

Regulatory and Rate Matters (Details) (USD $)			1 Months Ended	9 Months Ended																3 Months Ended			3 Months Ended		9 Months Ended	3 Months Ended	0 Months Ended	9 Months Ended				0 Months Ended	3 Months Ended				3 Months Ended			9 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended	1 Months Ended	3 Months Ended	0 Months Ended					0 Months Ended			1 Months Ended				0 Months Ended		1 Months Ended	3 Months Ended
	Sep. 30, 2013 Public Service Company of New Mexico [Member] Emergency FPPAC [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] La Luz Generating Station [Member] MW	Dec. 31, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] MW	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Minimum [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Maximum [Member]	Mar. 31, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Maximum [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Wind Energy [Member] Minimum [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Wind Energy [Member] Minimum [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Solar Energy [Member] Minimum [Member]	Sep. 30, 2012 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Solar Energy [Member] Minimum [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Renewable Technologies [Member] Minimum [Member]	Sep. 30, 2012 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Renewable Technologies [Member] Minimum [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Distributed Generation [Member] Minimum [Member]	Sep. 30, 2012 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Distributed Generation [Member] Minimum [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2011 [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2015 [Member]	Mar. 31, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2015 [Member] Distributed Generation [Member] Minimum [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2020 [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard Supplemental Procurement [Member] MW	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard Supplemental Procurement Reduction [Member] Minimum [Member] MW	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard Supplemental Procurement Reduction [Member] Maximum [Member] MW	Sep. 30, 2013 Public Service Company of New Mexico [Member] 2014 Wind generated Renewable Energy Credits [Member] MWh	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard 2014 [Member] MW	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard 2014 [Member] MW	Sep. 30, 2013 Public Service Company of New Mexico [Member] 2015 Wind generated Renewable Energy Credits [Member] MWh	Aug. 20, 2011 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	Nov. 29, 2010 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	May 03, 2010 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] Per KWh [Member] Maximum [Member]	May 03, 2010 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] Per kilowatt [Member]	Oct. 05, 2012 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Disincentives / Incentives Adder [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Disincentives / Incentives Adder [Member]	Aug. 11, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Disincentives / Incentives Adder [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Per KWh [Member] Amended [Member] Minimum [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Per kilowatt [Member] Amended [Member] Minimum [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Mar. 31, 2013 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Energy Rider [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Energy Rider [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Energy Rider [Member] Maximum [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Energy Rider [Member] Maximum [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member] Renewable Energy Rider [Member] Maximum [Member]	Jul. 31, 2011 Public Service Company of New Mexico [Member] Integrated Resource Plan, 2011 [Member] Protests_Filed	Sep. 30, 2013 Public Service Company of New Mexico [Member] Integrated Resource Plan, 2011 [Member]	Jul. 03, 2012 Public Service Company of New Mexico [Member] Transmission Rate Case [Member]	Oct. 27, 2010 Public Service Company of New Mexico [Member] Transmission Rate Case [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Formula Transmission Rate Case [Member]	Aug. 02, 2013 Public Service Company of New Mexico [Member] Formula Transmission Rate Case [Member]	Jan. 02, 2013 Public Service Company of New Mexico [Member] Formula Transmission Rate Case [Member]	Dec. 06, 2012 Public Service Company of New Mexico [Member] Firm Requirements Wholesale Power Rate Case [Member]	Sep. 15, 2011 Public Service Company of New Mexico [Member] Firm Requirements Wholesale Power Rate Case [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] City of Gallup, New Mexico Contract [Member]	Jul. 30, 2011 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	Sep. 30, 2013 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	Sep. 30, 2013 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] Minimum [Member]	Sep. 30, 2013 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] Maximum [Member]	Aug. 28, 2012 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Sep. 30, 2013 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Jan. 31, 2013 Texas-New Mexico Power Company [Member] Transmission Rate Filings [Member]	Sep. 30, 2013 Texas-New Mexico Power Company [Member] August 2013 Transmission Rate Filings [Member]	Sep. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member] Applications for Approvals to Purchase Delta [Member] MW
Rate Matters [Line Items]
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales																10.00%	15.00%		20.00%
Public Utilities, Required Percentage of Diversification								20.00%	30.00%	20.00%	20.00%	5.00%	10.00%	1.50%	1.50%			3.00%
Public Utilities, Reasonable Cost Threshold					2.00%	3.00%	3.00%
Public Utilities, Annual Incremental Increase in Reasonable Cost Threshold				0.25%
Public Utilities, Additional Renewable Procurements Spending Required by NMPRC			$ 900,000
Public Utilities, Number of Mega Watts of Solar PV Capacity				20																2	1.5	2		23	23
Public Utilities, Number of Mega Watts of Wind Energy Capacity																								100
Public Utilities, First Year Cost of Wind Capacity Planned Purchase Agreement																									5,800,000.0
Public Utilities, Number of Mega Watt Hours of Wind Generation																							50,000			120,000
Public Utilities, Requested Rider Rate For 2014																																								0.0044391
Public Utilities, Estimated Cost of Mega Watts of Solar PV Capacity				45,500,000																4,500,000					46,700,000
Public Utilities, Number of Mega Watts of Geothermal Capacity				10
Public Utilities, Wind Capacity Planned Purchase Agreement Term																									20 years
Public Utilities, Program Costs Related To Energy Efficiency																																22,500,000
Public Utilities, Proposed Profit Incentive Adder Revenues Related To Energy Efficiency Program																																4,200,000	2,900,000
Public Utilities, Rate Adder Allowed																														0.01	10				0.002	4
Public Utilities, Rate Rider Recovered																											2,600,000
Public Utilities, Regulatory Costs Approved																													4,200,000																					2,900,000
Percentage ownership of EIP transmission line																																																60.00%
Public Utilities, Eliminated Recovery of Adder Revenue																																		1,300,000
Public Utilities, Rate Rider Net Over-Recovery																												200,000
Public Utilities, Rate Rider Program Costs Over-Recovery																												1,000,000
Public Utilities, Rate Rider Incentives Under-Recovery																												800,000
Public Utilities, Rate Rider Estimated Incentives Under-Recovery																												500,000
Public Utilities, Regulatory Costs to be Collected																																					36,200,000	38,800,000
Public Utilities, Regulatory Costs Incurred and Eligible For Recovery, Amount Deferred for Collection in Future Period																																					38,400,000
Public Utilities, Additional Revenue To be Collected in 2012																																											18,000,000
Public Utilities, Additional Revenue To be Collected in 2013																																										24,600,000
Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013																																									10.50%
Public Utilities, Rate Rider to be Implemented																																							0.0030468	0.0030468
Public Utilities, Approved Rider Rate For 2012																																								0.0022335
Public Utilities, Approved Rider Rate For 2013																																								0.0028371
Public Utilities, Order Disapproved Recovery of Costs As Regulatory Agency Had Not Acted on Specific Procurements Proposed																																							900,000
Public Utilities, Planning Period Covered of IRP																																												20 years
Public Utilities, Number of protests that were filed to IRP requesting rejection of the plan																																												2
Amount of Regulatory Costs Not yet Approved	8,000,000																																														11,100,000	3,200,000	1,300,000			8,700,000
Public Utilities, Number of Mega Watts Natural Gas Peaking Units to be Purchased																																																														132
Public Utilities, Number of Mega Watts of Gas-fired Generation		40
Estimated Installation Capital Costs		63,200,000
Public Utilities, Return on Equity																																															12.25%	10.81%
Public Utilities, Regulatory Rate Increase																																																				39.80%
Public Utilities, Collection of Deployment Costs Through Surcharge Period																																																						12 years
Public Utilities, Completion Period of Advanced Meter Deployment																																																						5 years
Public Utilities, Non-standard metering service cost total to be borne by opt-out customers																																																							0
Public Utilities, Non-standard metering service cost initial fee range																																																								142.84	247.48
Public Utilities, Non-standard metering ongoing expenses total to be borne by opt-out customers																																																							500,000
Public Utilities, Non-standard metering ongoing expenses monthly charge																																																							38.99
Public Utilities, Increase Annual Transmission Service Revenue																																														2,900,000
Public Utilities, Additional Revenue from Proposed Rates																																																												21,900,000	18,100,000
Public Utilities, Total Revenue Requirement Increase																																																			5,300,000									2,900,000	2,800,000
Public Utilities, Contract Extension																																																			10 years
Public Utilities, Estimated Increase in Revenue over amendment term																																																					3,100,000
Public Utilities, Approved Deployment Costs																																																						113,300,000
Public Utilities, Approved Program Implementation Costs																																																										4,800,000
Public Utilities, Approved Program Implementation Costs, Bonus																																																										400,000
Public Utilities, Unapproved 2014 Program Implementation Costs																																																											5,600,000
Public Utilities, Unapproved 2014 Program Implementation Costs, Expense																																																											4,700,000
Public Utilities, Unapproved 2014 Program Implementation Costs, Bonus																																																											700,000
Public Utilities, Unapproved 2014 Program Implementation Costs, Overcollection refund																																																											$ 100,000
Public Utilities, Retention Percentage of Sales Margins																																					10.00%
Public Utilities, Frequency of IRP filings																																													3 years

XML

Financing, Short-term Debt (Details) (USD $)					3 Months Ended																					1 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Line of Credit [Member]	Dec. 31, 2012 Line of Credit [Member]	Sep. 30, 2013 Revolving Credit Facility [Member]	Sep. 30, 2013 PNM Resources [Member] Revolving Credit Facility [Member]	Dec. 31, 2012 PNM Resources [Member] Revolving Credit Facility [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Revolving Credit Facility [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member] Revolving Credit Facility [Member]	Sep. 30, 2013 Texas-New Mexico Power Company [Member]	Dec. 31, 2012 Texas-New Mexico Power Company [Member]	Sep. 30, 2013 Texas-New Mexico Power Company [Member] Revolving Credit Facility [Member]	Dec. 31, 2012 Texas-New Mexico Power Company [Member] Revolving Credit Facility [Member]	Oct. 25, 2013 Available Borrowing Capacity [Member]	Oct. 25, 2013 Available Borrowing Capacity [Member] PNM Resources [Member]	Oct. 25, 2013 Available Borrowing Capacity [Member] Public Service Company of New Mexico [Member]	Oct. 25, 2013 Available Borrowing Capacity [Member] Texas-New Mexico Power Company [Member]	Oct. 25, 2013 Subsequent Event [Member] PNM Resources [Member]	Oct. 25, 2013 Subsequent Event [Member] Public Service Company of New Mexico [Member]	Oct. 25, 2013 Subsequent Event [Member] Texas-New Mexico Power Company [Member]	Oct. 25, 2013 Affiliated Entity [Member] Intercompany loan agreements [Member] Texas-New Mexico Power Company [Member]	Sep. 30, 2013 PNMR Term Loan Agreement [Member]	Dec. 31, 2012 PNMR Term Loan Agreement [Member]	Dec. 31, 2012 PNMR Term Loan Agreement [Member] Notes Payable to Banks [Member]	Sep. 30, 2013 First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] Texas-New Mexico Power Company [Member] Revolving Credit Facility [Member]	Sep. 30, 2013 PNM Term Loan Agreement [Member] Notes Payable to Banks [Member]	Apr. 22, 2013 PNM Term Loan Agreement [Member] Notes Payable to Banks [Member]
Short-term Debt [Line Items]
Short term debt, number of options to extend					2
Debt Instrument, Interest Rate, Stated Percentage																												1.44%
Line of Credit Facility, Maximum Borrowing Capacity						$ 300,000,000				$ 400,000,000				$ 75,000,000
Debt Instrument, Collateral Amount																											75,000,000
Proceeds from Short-term Debt																										100,000,000
Short-term Debt, Weighted Average Interest Rate	1.31%											1.30%
Short-term debt	112,000,000	158,700,000	112,000,000	158,700,000		0	37,600,000	0	21,100,000	0	21,100,000	12,000,000	0	12,000,000	0									100,000,000	100,000,000				75,000,000
Line of Credit Facility, Remaining Borrowing Capacity																755,900,000	291,400,000	396,800,000	67,700,000
Short-term debt – affiliate												33,100,000	28,300,000										43,000,000
Restricted Cash and Investments																				$ 6,500,000	$ 15,700,000	$ 0
Short term debt, option to extend - period of extension					1 year

XML

Condensed Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Earnings	$ 54,555	$ 57,864	$ 92,859	$ 96,456
Net Earnings	58,814	61,976	104,159	107,551
Unrealized Gain on Investment Securities:
Unrealized holding gains arising during the period, net of income tax (expense) benefit	6,322	7,587	11,512	23,511
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(1,411)	(6,481)	(5,551)	(19,509)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit)	960	727	2,880	2,181
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	(238)	(92)	(236)	(270)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	35	29	99	85
Total Other Comprehensive Income (Loss)	5,668	1,770	8,704	5,998
Comprehensive Income	64,482	63,746	112,863	113,549
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,127)	(3,980)	(10,904)	(10,699)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(396)	(396)
Comprehensive Income Attributable to PNMR	60,223	59,634	101,563	102,454
Public Service Company of New Mexico [Member]
Net Earnings	47,823	50,911	85,516	85,607
Net Earnings	51,950	54,891	96,420	96,306
Unrealized Gain on Investment Securities:
Unrealized holding gains arising during the period, net of income tax (expense) benefit	6,322	7,587	11,512	23,511
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(1,411)	(6,481)	(5,551)	(19,509)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit)	960	727	2,880	2,181
Fair Value Adjustment for Cash Flow Hedges:
Total Other Comprehensive Income (Loss)	5,871	1,833	8,841	6,183
Comprehensive Income	57,821	56,724	105,261	102,489
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,127)	(3,980)	(10,904)	(10,699)
Comprehensive Income Attributable to PNMR	53,694	52,744	94,357	91,790
Texas-New Mexico Power Company [Member]
Net Earnings	10,106	9,084	22,170	20,113
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	(238)	(92)	(236)	(270)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	35	29	99	85
Total Other Comprehensive Income (Loss)	(203)	(63)	(137)	(185)
Comprehensive Income Attributable to PNMR	$ 9,903	$ 9,021	$ 22,033	$ 19,928

XML

Earnings Per Share

9 Months Ended

Sep. 30, 2013

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,
	2013		2012		2013		2012
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	54,555	$	57,864	$	92,859	$	96,456
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	177		114		194		156
Average Shares - Basic	79,831		79,768		79,848		79,810
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	503		622		608		600
Average Shares - Diluted	80,334		80,390		80,456		80,410
Net Earnings Per Share of Common Stock:
Basic	$	0.68	$	0.73	$	1.16	$	1.21
Diluted	$	0.68	$	0.72	$	1.15	$	1.20

⁽¹⁾  Excludes the effect of out-of-the-money options for 793,010 shares of common stock at September 30, 2013.

XML

Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash Flows From Operating Activities:
Net Earnings	$ 104,159	$ 107,551
Net Earnings	92,859	96,456
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	157,856	153,992
Deferred income tax expense	57,878	55,141
Net unrealized (gains) losses on commodity derivatives	(5,858)	3,076
Realized (gains) losses on investments held by NDT	(6,995)	(9,376)
Stock based compensation expense	4,315	2,748
Regulatory disallowances	1,735	0
Other, net	1,444	(2,037)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(23,731)	(31,550)
Materials, supplies, and fuel stock	(724)	(6,769)
Other current assets	(6,667)	(4,225)
Other assets	21,656	(9,499)
Accounts payable	(17,786)	3,973
Accrued interest and taxes	126,218	22,336
Other current liabilities	(32,111)	(21,681)
Proceeds from governmental grants	0	21,567
Other liabilities	(70,379)	(80,248)
Net cash flows from operating activities	311,010	204,999
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(233,928)	(214,743)
Proceeds from sales of investments held by NDT	179,336	136,305
Purchases of investments held by NDT	(181,401)	(138,658)
Proceeds from sale of First Choice	0	4,034
Return of principal on PVNGS lessor notes	23,357	23,455
Other, net	1,210	1,627
Net cash flows from investing activities	(211,426)	(187,980)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(46,700)	30,700
Long-term borrowings	75,000	20,000
Repayment of long-term debt	(26,037)	(20,000)
Cash paid in debt exchange	(13,048)	0
Proceeds from stock option exercise	3,500	10,301
Purchases to satisfy awards of common stock	(12,429)	(21,930)
Dividends paid	(38,233)	(33,454)
Valencia's transactions with its owner	(13,477)	(12,034)
Other, net	(3,706)	(337)
Net cash flows from financing activities	(75,130)	(26,754)
Change in Cash and Cash Equivalents	24,454	(9,735)
Cash and Cash Equivalents at Beginning of Period	8,985	15,091
Cash and Cash Equivalents at End of Period	33,439	5,356
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	71,824	64,040
Income taxes paid (refunded), net	(95,472)	5,302
Supplemental schedule of noncash financing activities:
Premium on long-term debt incurred in connection with debt exchange	23,249
Public Service Company of New Mexico [Member]
Cash Flows From Operating Activities:
Net Earnings	96,420	96,306
Net Earnings	85,516	85,607
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	104,161	97,086
Deferred income tax expense	49,870	52,558
Net unrealized (gains) losses on commodity derivatives	(5,858)	3,076
Realized (gains) losses on investments held by NDT	(6,995)	(9,376)
Regulatory disallowances	1,735	0
Other, net	(1,282)	(1,005)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(14,123)	(26,183)
Materials, supplies, and fuel stock	(744)	(6,404)
Other current assets	(5,187)	(6,942)
Other assets	21,977	(9,425)
Accounts payable	(4,953)	2,353
Accrued interest and taxes	66,090	80,418
Other current liabilities	(43,935)	(9,850)
Proceeds from governmental grants	0	21,567
Other liabilities	(67,062)	(75,629)
Net cash flows from operating activities	190,114	208,550
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(164,669)	(144,571)
Proceeds from sales of investments held by NDT	179,336	136,305
Purchases of investments held by NDT	(181,401)	(138,658)
Return of principal on PVNGS lessor notes	23,357	23,455
Other, net	1,212	(720)
Net cash flows from investing activities	(142,165)	(124,189)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(21,100)	(66,000)
Long-term borrowings	75,000	20,000
Repayment of long-term debt	0	(20,000)
Dividends paid	(68,424)	(18,076)
Valencia's transactions with its owner	(13,477)	(12,034)
Other, net	(1,727)	(337)
Net cash flows from financing activities	(29,728)	(96,447)
Change in Cash and Cash Equivalents	18,221	(12,086)
Cash and Cash Equivalents at Beginning of Period	3,958	12,307
Cash and Cash Equivalents at End of Period	22,179	221
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	49,984	43,167
Income taxes paid (refunded), net	(44,999)	(63,114)
Texas-New Mexico Power Company [Member]
Cash Flows From Operating Activities:
Net Earnings	22,170	20,113
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	40,946	41,222
Deferred income tax expense	3,901	11,337
Other, net	(13)	(275)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(9,608)	(5,367)
Materials, supplies, and fuel stock	20	(365)
Other current assets	(2,420)	(709)
Other assets	36	(498)
Accounts payable	(291)	(358)
Accrued interest and taxes	14,669	4,860
Other current liabilities	(1,946)	1,980
Other liabilities	2,182	(3,411)
Net cash flows from operating activities	69,646	68,529
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(67,400)	(59,801)
Net cash flows from investing activities	(67,400)	(59,801)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), affiliate, net	12,000	0
Long-term borrowings	4,800	2,300
Cash paid in debt exchange	(13,048)	0
Dividends paid	(3,726)	(11,028)
Other, net	(2,117)	0
Net cash flows from financing activities	(2,091)	(8,728)
Change in Cash and Cash Equivalents	155	0
Cash and Cash Equivalents at Beginning of Period	1	1
Cash and Cash Equivalents at End of Period	156	1
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	13,626	13,074
Income taxes paid (refunded), net	696	1,848
Supplemental schedule of noncash financing activities:
Premium on long-term debt incurred in connection with debt exchange	$ 23,249

XML

Condensed Consolidated Statements of Earnings (USD $) In Thousands, except Per Share data, unless otherwise specified	1 Months Ended		3 Months Ended		9 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Electric Operating Revenues			$ 399,730	$ 390,411	$ 1,064,993	$ 1,019,646
Operating Expenses:
Cost of energy			114,674	110,777	325,039	297,342
Administrative and general			46,915	45,283	134,744	135,371
Energy production costs			41,142	40,365	131,546	131,546
Regulatory disallowances			1,735	0	1,735	0
Depreciation and amortization			42,743	42,820	125,189	122,289
Transmission and distribution costs			17,248	17,082	50,690	50,896
Taxes other than income taxes			17,534	15,934	49,739	45,218
Total operating expenses			281,991	272,261	818,682	782,662
Operating income			117,739	118,150	246,311	236,984
Other Income and Deductions:
Interest income			2,264	3,130	7,731	9,808
Gains on investments held by NDT			2,190	5,716	6,995	9,376
Other income			3,252	2,484	7,517	6,991
Other (deductions)			(5,970)	(3,451)	(13,516)	(10,719)
Net other income (deductions)			1,736	7,879	8,727	15,456
Interest Charges			30,365	30,515	92,279	90,280
Earnings before Income Taxes			89,110	95,514	162,759	162,160
Income Taxes			30,296	33,538	58,600	54,609
Net Earnings			58,814	61,976	104,159	107,551
(Earnings) Attributable to Valencia Non-controlling Interest			(4,127)	(3,980)	(10,904)	(10,699)
Preferred Stock Dividend Requirements of Subsidiary			(132)	(132)	(396)	(396)
Net Earnings Attributable to PNMR			54,555	57,864	92,859	96,456
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)			$ 0.68	$ 0.73	$ 1.16	$ 1.21
Diluted (dollars per share)			$ 0.68	$ 0.72	$ 1.15	$ 1.20
Dividends Declared per Common Share (dollars per share)	$ 0.165	$ 0.145	$ 0.165	$ 0.145	$ 0.495	$ 0.435
Public Service Company of New Mexico [Member]
Electric Operating Revenues			326,026	321,731	863,609	832,242
Operating Expenses:
Cost of energy			100,200	99,217	283,715	263,009
Administrative and general			40,679	41,150	116,058	120,857
Energy production costs			41,142	40,365	131,546	131,546
Regulatory disallowances			1,735	0	1,735	0
Depreciation and amortization			25,879	24,437	77,763	72,017
Transmission and distribution costs			11,686	11,172	33,420	33,679
Taxes other than income taxes			9,488	8,417	28,613	25,386
Total operating expenses			230,809	224,758	672,850	646,494
Operating income			95,217	96,973	190,759	185,748
Other Income and Deductions:
Interest income			2,298	3,173	7,839	9,938
Gains on investments held by NDT			2,190	5,716	6,995	9,376
Other income			2,396	1,176	5,269	4,378
Other (deductions)			(2,375)	(1,682)	(5,287)	(4,553)
Net other income (deductions)			4,509	8,383	14,816	19,139
Interest Charges			20,124	19,230	59,971	56,652
Earnings before Income Taxes			79,602	86,126	145,604	148,235
Income Taxes			27,652	31,235	49,184	51,929
Net Earnings			51,950	54,891	96,420	96,306
(Earnings) Attributable to Valencia Non-controlling Interest			(4,127)	(3,980)	(10,904)	(10,699)
Net Earnings Attributable to PNMR			47,823	50,911	85,516	85,607
Preferred Stock Dividends Requirements			(132)	(132)	(396)	(396)
Net Earnings Available for PNM Common Stock			47,691	50,779	85,120	85,211
Texas-New Mexico Power Company [Member]
Electric Operating Revenues			73,704	68,680	201,384	187,404
Operating Expenses:
Cost of energy			14,474	11,560	41,324	34,333
Administrative and general			10,641	10,130	32,446	30,700
Depreciation and amortization			13,850	13,819	37,810	37,173
Transmission and distribution costs			5,562	5,910	17,270	17,217
Taxes other than income taxes			6,923	6,291	17,558	16,322
Total operating expenses			51,450	47,710	146,408	135,745
Operating income			22,254	20,970	54,976	51,659
Other Income and Deductions:
Interest income			0	0	0	1
Other income			820	771	1,765	1,708
Other (deductions)			(104)	(405)	(356)	(464)
Net other income (deductions)			716	366	1,409	1,245
Interest Charges			6,655	7,047	20,661	21,214
Earnings before Income Taxes			16,315	14,289	35,724	31,690
Income Taxes			6,209	5,205	13,554	11,577
Net Earnings Attributable to PNMR			$ 10,106	$ 9,084	$ 22,170	$ 20,113

XML

Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Service billings [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 2	$ 4	$ 6	$ 12
Service billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	22,241	22,143	65,729	68,030
Service billings [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	6,731	6,439	20,948	20,206
Service billings [Member] | PNM to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	140	184	381	473
Interest charges [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	1	1
Interest charges [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	139	22	354	72
Interest charges [Member] | PNM to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	35	45	113	134
Income tax sharing payments [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	45,000	63,114
Income tax sharing payments [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 0	$ 0	$ 0	$ 1,952

XML

Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	54,555	$	57,864	$	92,859	$	96,456
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	177		114		194		156
Average Shares - Basic	79,831		79,768		79,848		79,810
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	503		622		608		600
Average Shares - Diluted	80,334		80,390		80,456		80,410
Net Earnings Per Share of Common Stock:
Basic	$	0.68	$	0.73	$	1.16	$	1.21
Diluted	$	0.68	$	0.72	$	1.15	$	1.20

⁽¹⁾  Excludes the effect of out-of-the-money options for 793,010 shares of common stock at September 30, 2013.

XML

Sale of First Choice

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Sale of First Choice

Sale of First Choice

On September 23, 2011, PNMR entered into an agreement for the sale of First Choice to Direct LP, Inc. for $270.0 million, subject to adjustment to reflect the amounts of certain components of working capital at closing. Closing occurred on November 1, 2011. For accounting purposes, the sale was effective as of the close of business on October 31, 2011. PNMR and the purchaser disagreed about the calculation of working capital at October 31, 2011. In accordance with the agreement for the sale, this matter was submitted to an independent party for a decision binding on the parties. A decision was received in August 2012. The decision resulted in PNMR being awarded $6.4 million of the $8.2 million in dispute. PNMR recorded an additional pre-tax gain of $1.0 million, which is included in other income in the three months ended September 30, 2012.

XML

Stock-Based Compensation (Details) (USD $)	9 Months Ended			9 Months Ended					12 Months Ended				9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2013 Stock Options [Member]	Sep. 30, 2013 Restricted Stock [Member]	Sep. 30, 2012 Restricted Stock [Member]	Sep. 30, 2013 Market-Based Shares [Member]	Sep. 30, 2012 Market-Based Shares [Member]	Dec. 31, 2012 Executive [Member] Performance Shares [Member]	Sep. 30, 2013 Executive [Member] Performance Shares [Member]	Sep. 30, 2013 Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee [Member] Common Stock [Member] Chairman, President, and Chief Executive Officer [Member]	Sep. 30, 2013 Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 and she remains an employee [Member] Common Stock [Member] Chairman, President, and Chief Executive Officer [Member]	Sep. 30, 2013 Performance Equity Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period													3 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options, Outstanding at beginning of period, Shares	1,992,700
Options, Outstanding at beginning of period, Weighted-Average Exercise Price (in dollars per share)	$ 20.72
Options, Granted, Shares	0
Options, Granted, Weighted-Average Exercise Price (in dollars per share)	$ 0.00
Options, Exercised, Shares	(260,579)
Options, Exercised, Weighted-Average Exercise Price (in dollars per share)	$ 13.43
Options, Forfeited, Shares	0
Options, Forfeited, Weighted-Average Exercise Price (in dollars per share)	$ 0.00
Options, Expired, Shares	(292,644)
Options, Expired, Weighted-Average Exercise Price (in dollars per share)	$ 27.23
Options, Outstanding at end of period, Shares	1,439,477
Options, Outstanding at end of period, Weighted-Average Exercise Price (in dollars per share)	$ 20.72
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options, Outstanding at end of period, Aggregate Intrinsic Value				$ 6,700,000
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years)				3 years 6 months 22 days
Options, Outstanding at end of period, No intrinsic value	793,010
Weighted-average grant date fair value options granted (dollars per share)	$ 0.00	$ 0.00
Total fair value of options that vested	625,000	1,058,000
Total intrinsic value of options exercised	2,466,000	4,515,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Nonvested Restricted Stock, Nonvested at beginning of period, Shares					353,722
Nonvested Restricted Stock, Nonvested at beginning of period, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 14.03
Nonvested Restricted Stock, Granted, Shares					249,113
Nonvested Restricted Stock, Granted, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 20.03	$ 15.63
Nonvested Restricted Stock, Vested, Shares					(275,988)
Nonvested Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 15.92
Nonvested Restricted Stock, Forfeited, Shares					(8,366)
Nonvested Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 18.37
Nonvested Restricted Stock, Nonvested at end of period, Shares					318,481
Nonvested Restricted Stock, Nonvested at end of period, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 17.88
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Total fair value of shares that vested					4,395,000	4,755,000
Expected quarterly dividends per share					$ 0.165	$ 0.145
Risk-free interest rate					0.34%	0.65%	0.36%	1.04%
Granted and Vested in Period									100,953
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year One										188,129
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Two										198,369
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Three										179,811
Shares received if achieves specified improvement in total shareholders return											135,000	35,000
Share-based Compensation Arrangement by Share-based Payment Award, Vesting Rate													100.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate							2.86%	3.45%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate							25.11%	43.98%
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 5,700,000		$ 3,800,000

XML

Sale of First Choice (Details) (First Choice [Member], USD $) In Millions, unless otherwise specified	0 Months Ended	1 Months Ended		3 Months Ended
	Sep. 23, 2011	Aug. 31, 2012	Oct. 31, 2011	Sep. 30, 2012 Other Income [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	$ 270.0
Business Disposition, Awarded Purchase Price Disputed		6.4
Business Disposition, Sale Price Disputed			8.2
Gain (Loss) on Disposition of Business				$ 1.0

XML

Fair Value of Derivative and Other Financial Instruments, Margin, Notional Amounts, Credit Rating (Details) (PNMR and PNM [Member], USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Derivative [Line Items]
Contractual Liability	$ 2,250	$ 2,933
Existing Cash Collateral	0	0
Net Exposure	$ 2,224	$ 2,777
Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Long Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	(3,801,738)	1,127,500

XML

Accumulated Other Comprehensive Income (Loss) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Equity [Abstract]
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process			19.60%
Percentage of Pension Liability Adjustment Capitalized into Other Accounts			1.10%
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			$ (81,630)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			(4,264)
Income tax impact of amounts reclassified from accumulated other comprehensive income			1,692
Other Comprehensive Income (Loss), before Reclassifications, before Tax			18,693
Other Comprehensive Income (Loss), Tax			(7,417)
Total Other Comprehensive Income (Loss)	5,668	1,770	8,704	5,998
Balance at March 31, 2013	(72,926)		(72,926)
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			16,406
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			(9,190)
Income tax impact of amounts reclassified from accumulated other comprehensive income			3,639
Other Comprehensive Income (Loss), before Reclassifications, before Tax			19,056
Other Comprehensive Income (Loss), Tax			(7,544)
Total Other Comprehensive Income (Loss)			5,961
Balance at March 31, 2013	22,367		22,367
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			(97,820)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			4,773
Income tax impact of amounts reclassified from accumulated other comprehensive income			(1,893)
Other Comprehensive Income (Loss), before Reclassifications, before Tax			0
Other Comprehensive Income (Loss), Tax			0
Total Other Comprehensive Income (Loss)			2,880
Balance at March 31, 2013	(94,940)		(94,940)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			(216)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			153
Income tax impact of amounts reclassified from accumulated other comprehensive income			(54)
Other Comprehensive Income (Loss), before Reclassifications, before Tax			(363)
Other Comprehensive Income (Loss), Tax			127
Total Other Comprehensive Income (Loss)			(137)
Balance at March 31, 2013	(353)		(353)
Public Service Company of New Mexico [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			(81,414)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			(4,417)
Income tax impact of amounts reclassified from accumulated other comprehensive income			1,746
Other Comprehensive Income (Loss), before Reclassifications, before Tax			19,056
Other Comprehensive Income (Loss), Tax			(7,544)
Total Other Comprehensive Income (Loss)	5,871	1,833	8,841	6,183
Balance at March 31, 2013	(72,573)		(72,573)
Public Service Company of New Mexico [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			16,406
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			(9,190)
Income tax impact of amounts reclassified from accumulated other comprehensive income			3,639
Other Comprehensive Income (Loss), before Reclassifications, before Tax			19,056
Other Comprehensive Income (Loss), Tax			(7,544)
Total Other Comprehensive Income (Loss)			5,961
Balance at March 31, 2013	22,367		22,367
Public Service Company of New Mexico [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			(97,820)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			4,773
Income tax impact of amounts reclassified from accumulated other comprehensive income			(1,893)
Other Comprehensive Income (Loss), before Reclassifications, before Tax			0
Other Comprehensive Income (Loss), Tax			0
Total Other Comprehensive Income (Loss)			2,880
Balance at March 31, 2013	(94,940)		(94,940)
Public Service Company of New Mexico [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			0
Income tax impact of amounts reclassified from accumulated other comprehensive income			0
Other Comprehensive Income (Loss), before Reclassifications, before Tax			0
Other Comprehensive Income (Loss), Tax			0
Total Other Comprehensive Income (Loss)			0
Balance at March 31, 2013	0		0
Texas-New Mexico Power Company [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			(216)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			153
Income tax impact of amounts reclassified from accumulated other comprehensive income			(54)
Other Comprehensive Income (Loss), before Reclassifications, before Tax			(363)
Other Comprehensive Income (Loss), Tax			127
Total Other Comprehensive Income (Loss)	(203)	(63)	(137)	(185)
Balance at March 31, 2013	(353)		(353)
Texas-New Mexico Power Company [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			0
Income tax impact of amounts reclassified from accumulated other comprehensive income			0
Other Comprehensive Income (Loss), before Reclassifications, before Tax			0
Other Comprehensive Income (Loss), Tax			0
Total Other Comprehensive Income (Loss)			0
Balance at March 31, 2013	0		0
Texas-New Mexico Power Company [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			0
Income tax impact of amounts reclassified from accumulated other comprehensive income			0
Other Comprehensive Income (Loss), before Reclassifications, before Tax			0
Other Comprehensive Income (Loss), Tax			0
Total Other Comprehensive Income (Loss)			0
Balance at March 31, 2013	0		0
Texas-New Mexico Power Company [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at December 31, 2012			(216)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			153
Income tax impact of amounts reclassified from accumulated other comprehensive income			(54)
Other Comprehensive Income (Loss), before Reclassifications, before Tax			(363)
Other Comprehensive Income (Loss), Tax			127
Total Other Comprehensive Income (Loss)			(137)
Balance at March 31, 2013	$ (353)		$ (353)

XML

Variable Interest Entities (Details) (USD $)	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended						1 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2013 Public Service Company of New Mexico [Member]	Sep. 30, 2012 Public Service Company of New Mexico [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member]	Sep. 30, 2012 Public Service Company of New Mexico [Member]	Dec. 31, 2012 Public Service Company of New Mexico [Member]	Sep. 30, 2013 Valencia [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2012 Valencia [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Valencia [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2012 Valencia [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2012 Valencia [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2012 Delta [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2012 Delta [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2012 Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Palo Verde Nuclear Generating Station [Member] Property Lease Guarantee [Member] Maximum [Member] Public Service Company of New Mexico [Member]	May 30, 2008 Purchased Through May 30, 2028 [Member] Valencia [Member] Public Service Company of New Mexico [Member] MW	Dec. 31, 2012 Delta [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Number of mega watts purchased (in megawatts)																							145
Long Term Contract For Purchase of Electric Power Fixed Costs											$ 4,800,000	$ 4,800,000	$ 14,100,000	$ 14,000,000		$ 1,600,000	$ 1,600,000	$ 4,800,000	$ 4,700,000
Long Term Contract For Purchase of Electric Power Variable Charges											700,000	600,000	1,000,000	900,000		700,000	300,000	1,300,000	600,000
Variable Interest Entity, Statement Of Operation [Abstract]
Operating revenues											5,453,000	5,358,000	15,150,000	14,916,000
Operating expenses											(1,326,000)	(1,378,000)	(4,246,000)	(4,217,000)
Earnings Attributable to non-controlling interest	4,127,000	3,980,000	10,904,000	10,699,000		4,127,000	3,980,000	10,904,000	10,699,000		4,127,000	3,980,000	10,904,000	10,699,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	400,520,000		400,520,000		442,191,000	380,216,000		380,216,000		387,689,000	3,457,000		3,457,000		3,655,000
Net property, plant and equipment											75,841,000		75,841,000		77,953,000
Assets	5,428,814,000	5,260,207,000	5,428,814,000	5,260,207,000	5,372,583,000	4,192,470,000		4,192,470,000		4,163,907,000	79,298,000		79,298,000		81,608,000
Current liabilities	415,593,000		415,593,000		434,103,000	186,272,000		186,272,000		242,751,000	1,028,000		1,028,000		765,000
Owners' equity - non-controlling interest	78,270,000		78,270,000		80,843,000	78,270,000		78,270,000		80,843,000	78,270,000		78,270,000		80,843,000
Operating Leases, Fixed Rate Percentage of Renewal Options After Original Lease Term								50.00%
Operating Leases, Renewal Options After Original Lease Term (in years)								2 years
Operating Lease, Percentage of Unit 2 Capacity That May Be Extended								14.00%
Operating Leases, Extended Lease Term Option (in years)								6 years
Operating Leases, Future Minimum Payments Due																				52,600,000
Loss Contingency, Range of Possible Loss, Portion Not Accrued																						154,100,000
Operating Leases, Future Minimum Payments Due, Next Six Months																				11,800,000	26,000,000
Long Term Contract for Purchase of Electric Power Aggregate Amount of Contract Remaining																40,700,000		40,700,000
Payments to Acquire Businesses, Gross																								23,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt																									16,900,000	16,900,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt																									3,200,000	3,200,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets																									25,300,000	25,300,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment																									21,000,000	21,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities																									18,900,000	18,900,000
Revenues																									2,800,000	6,800,000
Net Earnings	$ 54,555,000	$ 57,864,000	$ 92,859,000	$ 96,456,000		$ 47,823,000	$ 50,911,000	$ 85,516,000	$ 85,607,000																$ 600,000	$ 900,000
Long term contract option to purchase, ownership percentage											50.00%
Long term contract option to purchase, number of days to set FMV											60 days
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, approximate approval period											15 months

XML

Fair Value of Derivative and Other Financial Instruments

9 Months Ended

Sep. 30, 2013

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

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. The Company'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. 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, to the extent not covered by the FPPAC. 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. Additional information concerning the Company's energy related derivative contracts, including how commodity risk is managed, is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

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. Energy contracts that meet the definition of a derivative under GAAP and do not qualify, or are not designated, for the normal sales and purchases exception are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met and elected. Normal sales and purchases are not marked to market and are reflected in results of operations when the underlying transactions physically settle.

During the nine months ended September 30, 2013 and the year ended December 31, 2012, 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 economic hedge. The Company does not enter into speculative trading transactions.

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

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, 2013			December 31, 2012
PNMR and PNM	(In thousands)
Current assets	$	5,743		$	3,785
Deferred charges	4,284			352
	10,027			4,137
Current liabilities	(1,017		)	(1,000		)
Long-term liabilities	(1,347		)	(1,933		)
	(2,364		)	(2,933		)
Net	$	7,663		$	1,204

Included in the above table are $2.3 million of current assets and $3.8 million of deferred charges related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium. Certain of PNM's commodity derivative instruments included 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, 2013 and December 31, 2012.

At September 30, 2013 and December 31, 2012, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at September 30, 2013 and December 31, 2012, amounts posted as cash collateral under margin arrangements were $2.0 million and $1.9 million for both PNMR and PNM. PNMR and PNM had no obligation to return cash collateral at September 30, 2013 and December 31, 2012. Cash collateral amounts are included in other current assets 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 $0.6 million of current assets, $0.1 million of deferred charges and $0.1 million of current liabilities at September 30, 2013 and less than $0.1 million of current assets at December 31, 2012 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 on earnings, excluding income tax effects and settlements, of commodity derivative instruments that are recorded at fair value. Commodity derivatives had no impact on OCI for the periods presented.

	Economic Hedges
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013		2012
PNMR and PNM	(In thousands)
Electric operating revenues	$	7,077		$	(740	)	$	5,743	$	897
Cost of energy	(72		)	263			421		(278		)
Total gain (loss)	$	7,005		$	(477	)	$	6,164	$	619

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
September 30, 2013
PNMR and PNM	980,000	(3,801,738	)
December 31, 2012
PNMR and PNM	1,127,500	(2,477,520	)

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

The table below presents information about the Company's contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company's revolving credit facilities that have been issued as

collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and 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)
September 30, 2013
PNMR and PNM	$	2,250	$	—	$	2,224
December 31, 2012
PNMR and PNM	$	2,933	$	—	$	2,777

Sale of Power from PVNGS Unit 3

Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of September 30, 2013, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium.  PNM has established fixed rates for substantially all of these sales through the end of 2013 through derivative contracts that are accounted for as economic hedges. PNM is also substantially hedged for 2014.

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, which include unrealized gains on securities which have not been recognized in net earnings. 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 a trust for PNM's share of post-term reclamation

costs related to the coal mines serving SJGS, which investments are included in "other investments" on the Condensed Consolidated Balance Sheet. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	September 30, 2013				December 31, 2012
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Cash and cash equivalents	$	—	$	24,414	$	—	$	4,628
Equity securities:
Domestic value	10,519		34,967		5,223		30,044
Domestic growth	23,355		67,527		15,212		51,650
International and other	1,543		16,159		247		14,868
Fixed income securities:
U.S. Government	262		16,711		1,305		32,592
Municipals	1,120		37,074		4,069		43,861
Corporate and other	221		14,553		1,100		14,868
	$	37,020	$	211,405	$	27,156	$	192,511

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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In thousands)
Proceeds from sales	$	103,230		$	90,518		$	179,336		$	136,305
Gross realized gains	$	2,611		$	6,263		$	8,962		$	11,029
Gross realized (losses)	$	(1,202	)	$	(5,131	)	$	(2,920	)	$	(7,055	)

Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. Held-to-maturity securities consist of the investment in PVNGS lessor notes and certain items within other investments.

At September 30, 2013, 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		PNM
	(In thousands)
Within 1 year	$	1,284	$	4,840	$	1,138
After 1 year through 5 years	16,768		55,310		53,956
After 5 years through 10 years	8,027		—		—
After 10 years through 15 years	3,277		—		—
After 15 years through 20 years	5,512		—		—
After 20 years	33,470		—		—
	$	68,338	$	60,150	$	55,094

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.

Fair Value Disclosures

The Company determines the fair values of its derivative and other 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 can 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.

For the NDT and reclamation trust investments, 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 long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar type assets and liabilities. Management of the Company independently verifies the information provided by pricing services.

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, 2013 and 2012.

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2013	(In thousands)
PNMR and PNM
Decommissioning and reclamation investments:
Cash and cash equivalents	$	24,414		$	24,414	$	—
Equity securities:
Domestic value	34,967			34,967		—
Domestic growth	67,527			67,527		—
International and other	16,159			16,159		—
Fixed income securities:
U.S. government	16,711			14,949		1,762
Municipals	37,074			—		37,074
Corporate and other	14,553			—		14,553
	$	211,405		$	158,016	$	53,389
Commodity derivative assets	$	10,027		$	—	$	10,027
Commodity derivative liabilities	(2,364		)	—		(2,364		)
Net	$	7,663		$	—	$	7,663
December 31, 2012
PNMR and PNM
Decommissioning and reclamation investments:
Cash and cash equivalents	$	4,628		$	4,628	$	—
Equity securities:
Domestic value	30,044			30,044		—
Domestic growth	51,650			51,650		—
International and other	14,868			14,868		—
Fixed income securities:
U.S. government	32,592			27,737		4,855
Municipals	43,861			—		43,861
Corporate and other	14,868			—		14,868
	$	192,511		$	128,927	$	63,584
Commodity derivative assets	$	4,137		$	—	$	4,137
Commodity derivative liabilities	(2,933		)	—		(2,933		)
Net	$	1,204		$	—	$	1,204

There were no Level 3 fair value measurements at September 30, 2013 or December 31, 2012.

The carrying amounts and fair values of investments in 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, 2013	(In thousands)
PNMR
Long-term debt	$	1,748,841	$	1,929,828	$	—	$	1,926,126	$	3,702
Investment in PVNGS lessor notes	$	53,300	$	55,094	$	—	$	—	$	55,094
Other investments	$	2,803	$	6,941	$	739	$	—	$	6,202
PNM
Long-term debt	$	1,290,608	$	1,400,109	$	—	$	1,400,109	$	—
Investment in PVNGS lessor notes	$	53,300	$	55,094	$	—	$	—	$	55,094
Other investments	$	458	$	458	$	458	$	—	$	—
TNMP
Long-term debt	$	336,128	$	393,122	$	—	$	393,122	$	—
Other investments	$	281	$	281	$	281	$	—	$	—
December 31, 2012
PNMR
Long-term debt	$	1,672,290	$	1,969,362	$	—	$	1,966,725	$	2,637
Investment in PVNGS lessor notes	$	77,682	$	84,198	$	—	$	—	$	84,198
Other investments	$	5,599	$	6,965	$	774	$	—	$	6,191
PNM
Long-term debt	$	1,215,579	$	1,385,433	$	—	$	1,385,433	$	—
Investment in PVNGS lessor notes	$	77,682	$	84,198	$	—	$	—	$	84,198
Other investments	$	494	$	494	$	494	$	—	$	—
TNMP
Long-term debt	$	311,589	$	418,166	$	—	$	418,166	$	—
Other investments	$	281	$	281	$	281	$	—	$	—

XML

Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2013

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

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

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	2013			2012
Expected quarterly dividends per share	$	0.165		$	0.145
Risk-free interest rate	0.34		%	0.65		%
Market-Based Shares
Dividend yield	2.86		%	3.45		%
Expected volatility	25.11		%	43.98		%
Risk-free interest rate	0.36		%	1.04		%

The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the nine months endedSeptember 30, 2013:

	Stock Option Shares		Weighted- Average Exercise Price		Restricted Stock		Weighted- Average Grant Date Fair Value
Outstanding at beginning of period	1,992,700		$	20.72	353,722		$	14.03
Granted	—		$	—	249,113		$	20.03
Exercised	(260,579	)	$	13.43	(275,988	)	$	15.92
Forfeited	—		$	—	(8,366	)	$	18.37
Expired	(292,644	)	$	27.23	—		$	—
Outstanding at end of period	1,439,477		$	20.72	318,481		$	17.88

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

	Nine Months Ended September 30,
Stock Options	2013		2012
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	625	$	1,058
Total intrinsic value of options exercised (in thousands)	$	2,466	$	4,515
Restricted Stock
Weighted-average grant date fair value	$	20.03	$	15.63
Total fair value of restricted shares that vested (in thousands)	$	4,395	$	4,755

XML

Fair Value of Derivative and Other Financial Instruments, Recurring (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Net		$ 281
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Net		0
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Net		0
PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	211,405	192,511
PNMR and PNM [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	211,405	192,511
PNMR and PNM [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	158,016	128,927
PNMR and PNM [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	53,389	63,584
PNMR and PNM [Member] | Cash and equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	24,414	4,628
PNMR and PNM [Member] | Cash and equivalents [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	24,414	4,628
PNMR and PNM [Member] | Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	24,414	4,628
PNMR and PNM [Member] | Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | Domestic value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	34,967	30,044
PNMR and PNM [Member] | Domestic value [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	34,967	30,044
PNMR and PNM [Member] | Domestic value [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	34,967	30,044
PNMR and PNM [Member] | Domestic value [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | Domestic growth [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	67,527	51,650
PNMR and PNM [Member] | Domestic growth [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	67,527	51,650
PNMR and PNM [Member] | Domestic growth [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	67,527	51,650
PNMR and PNM [Member] | Domestic growth [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | International and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	16,159	14,868
PNMR and PNM [Member] | International and other [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	16,159	14,868
PNMR and PNM [Member] | International and other [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	16,159	14,868
PNMR and PNM [Member] | International and other [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | U.S. Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	16,711	32,592
PNMR and PNM [Member] | U.S. Government [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	16,711	32,592
PNMR and PNM [Member] | U.S. Government [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	14,949	27,737
PNMR and PNM [Member] | U.S. Government [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,762	4,855
PNMR and PNM [Member] | Municipals [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	37,074	43,861
PNMR and PNM [Member] | Municipals [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	37,074	43,861
PNMR and PNM [Member] | Municipals [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | Municipals [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	37,074	43,861
PNMR and PNM [Member] | Corporate and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	14,553	14,868
PNMR and PNM [Member] | Corporate and other [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	14,553	14,868
PNMR and PNM [Member] | Corporate and other [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | Corporate and other [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	14,553	14,868
Public Service Company of New Mexico [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,400,109	1,385,433
Investment In PVNGS lessor notes	55,094	84,198
Other investments	458	494
Public Service Company of New Mexico [Member] | 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	0
Other investments	458	494
Public Service Company of New Mexico [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,400,109	1,385,433
Investment In PVNGS lessor notes	0	0
Other investments	0	0
Public Service Company of New Mexico [Member] | 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	55,094	84,198
Other investments	0	0
PNM Resources [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,929,828	1,969,362
Investment In PVNGS lessor notes	55,094	84,198
Other investments	6,941	6,965
PNM Resources [Member] | 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	0
Other investments	739	774
PNM Resources [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,926,126	1,966,725
Investment In PVNGS lessor notes	0	0
Other investments	0	0
PNM Resources [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	3,702	2,637
Investment In PVNGS lessor notes	55,094	84,198
Other investments	6,202	6,191
Texas-New Mexico Power Company [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	393,122	418,166
Other investments	281	281
Texas-New Mexico Power Company [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	281
Texas-New Mexico Power Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	393,122	418,166
Other investments	0
Texas-New Mexico Power Company [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	0
Commodity Contract [Member] | PNMR and PNM [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	10,027	4,137
Commodity derivative instruments, Liabilities	(2,364)	(2,933)
Commodity derivative instruments, Net	7,663	1,204
Commodity Contract [Member] | PNMR and PNM [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	0	0
Commodity derivative instruments, Liabilities	0	0
Commodity derivative instruments, Net	0	0
Commodity Contract [Member] | PNMR and PNM [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	10,027	4,137
Commodity derivative instruments, Liabilities	(2,364)	(2,933)
Commodity derivative instruments, Net	7,663	1,204
Carrying Amount [Member] | Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,290,608	1,215,579
Investment In PVNGS lessor notes	53,300	77,682
Other investments	458	494
Carrying Amount [Member] | PNM Resources [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,748,841	1,672,290
Investment In PVNGS lessor notes	53,300	77,682
Other investments	2,803	5,599
Carrying Amount [Member] | Texas-New Mexico Power Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	336,128	311,589
Other investments	$ 281	$ 281

XML

Financing

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Financing

Financing

Additional information concerning financing activities, including a TNMP cash-flow hedge that establishes a fixed interest rate on a variable rate loan, is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

Short-term Debt

PNMR has a revolving credit financing capacity of $300.0 million under the PNMR Revolving Credit Facility. PNM has a revolving credit financing capacity of $400.0 million under the PNM Revolving Credit Facility. Both of these facilities currently expire on October 31, 2018. In December 2012, PNMR borrowed $100.0 million under the PNMR Term Loan Agreement, which matures in December 2013. TNMP has a revolving credit financing capacity of $75.0 million under the TNMP Revolving Credit Facility that is secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. On September 18, 2013, the TNMP Revolving Credit Facility was amended and restated to extend its maturity from December 16, 2015 to September 18, 2018. At September 30, 2013, the weighted average interest rate was 1.31% for borrowings outstanding under the PNMR Term Loan Agreement, 1.44% for the PNM Term Loan Agreement, and 1.30% for the TNMP Revolving Credit Facility. Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2013		2012
	(In thousands)
PNM – Revolving credit facility	$	—	$	21,100
TNMP – Revolving credit facility	12,000		—
PNMR:
Revolving credit facility	—		37,600
PNMR Term Loan Agreement	100,000		100,000
	$	112,000	$	158,700

At October 25, 2013, PNMR, PNM, and TNMP had $291.4 million, $396.8 million, and $67.7 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit. Total availability at October 25, 2013, on a consolidated basis, was $755.9 million for PNMR. As of October 25, 2013, TNMP had $43.0 million in borrowings from PNMR under their intercompany loan agreement. At October 25, 2013, PNMR, PNM and TNMP had consolidated invested cash of $6.5 million, $15.7 million, and none.

Financing Activities

On March 6, 2013, TNMP commenced an offer to exchange any and all of TNMP's $265.5 million aggregate principal amount outstanding 9.50% First Mortgage Bonds, due 2019, Series 2009A, for a new series of 6.95% First Mortgage Bonds, due 2043, Series 2013A, and up to $140 in cash for each $1,000 of bonds exchanged. Settlement of the exchange offer occurred on April 3, 2013. Upon settlement, TNMP issued $93.2 million of 6.95% First Mortgage Bonds and paid an aggregate of $13.0 million in cash in exchange for $93.2 million of 9.50% First Mortgage Bonds, in addition to payment of accrued and unpaid interest on the exchanged bonds. The exchange resulted in the recording of a $23.2 million premium on the 6.95% First Mortgage Bonds reflecting the contractual interest rate being in excess of the market rate of interest on the date of the exchange. A regulatory asset was recorded offsetting the premium and the cash consideration paid in the exchange.

On April 22, 2013, PNM entered into a $75.0 million Term Loan Agreement (the "PNM Term Loan Agreement") among PNM, the lenders identified therein, and Union Bank, N.A., as Administrative Agent. Funding of the PNM Term Loan Agreement occurred on April 22, 2013, at which time the funds were used to repay $75.0 million in borrowings made under the PNM Revolving Credit Facility. The PNM Term Loan Agreement bears interest at a variable rate, which was 1.44% at September 30, 2013, must be repaid on or before October 21, 2014, and is reflected as long-term debt on the Condensed Consolidated Balance Sheets. The PNM Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Term Loan Agreement has a cross default provision and a change of control provision.

In the nine months ended September 30, 2013, PNMR purchased $23.0 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, for $26.0 million plus accrued and unpaid interest.

On October 2, 2013, the NMPRC approved PNM's application to enter into a new revolving credit facility of up to $50.0 million with banks operating in New Mexico. PNM anticipates entering into a facility in late 2013.

In October 2013, the second of the two1-year extension options for the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility were exercised extending the expiration of both facilities to October 31, 2018.

XML

Variable Interest Entities

9 Months Ended

Sep. 30, 2013

Variable Interest Entities

Variable Interest Entities

Variable Interest Entities

GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, including determining the primary beneficiary of a variable interest entity, by 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. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. Additional information concerning PNM's variable interest entities is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

Valencia

PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 145 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 operations and maintenance charges under this PPA. For the three and nine months ended September 30, 2013, PNM paid $4.8 million and $14.1 million for fixed charges and $0.7 million and $1.0 million for variable charges. For the three and nine months ended September 30, 2012, PNM paid $4.8 million and $14.0 million for fixed charges and $0.6 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 variable interest entity and that PNM is the primary beneficiary of the entity under GAAP. As the primary beneficiary, PNM consolidates the entity 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.

During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity.

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 will be initiated if the parties fail to reach agreement on fair market value within 60 days. After the purchase price has been determined, PNM may in its sole discretion determine whether or not it desires to exercise its option to purchase the 50% interest. In that regard, PNM will evaluate all its alternatives with respect to Valencia with the goal of achieving a fair and economical benefit for its customers. Also, PNM is in the process of developing its 2014 IRP (Note 11). Through this process, PNM will evaluate all of its resource options including Valencia to determine the optimal way to serve its customers. If PNM decides to exercise its option, the approval of the NMPRC and FERC would be required, which process could take up to 15 months. Since the purchase price is yet to be established, PNM cannot determine whether or not it will exercise its option or if required regulatory approvals would be received.

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Operating revenues	$	5,453		$	5,358		$	15,150		$	14,916
Operating expenses	(1,326		)	(1,378		)	(4,246		)	(4,217		)
Earnings attributable to non-controlling interest	$	4,127		$	3,980		$	10,904		$	10,699

Financial Position

	September 30,		December 31,
	2013		2012
	(In thousands)
Current assets	$	3,457	$	3,655
Net property, plant, and equipment	75,841		77,953
Total assets	79,298		81,608
Current liabilities	1,028		765
Owners' equity – non-controlling interest	$	78,270	$	80,843

PVNGS Leases

PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. PNM is not the legal or tax owner of the leased assets. PNM has an option to purchase the leased assets at appraised value at the end of the leases, but does not have a fixed price purchase option and does not provide residual value guarantees. As set forth in the leases, PNM has options to renew the leases at fixed rates, which represent 50% of the amounts during the original terms of the leases, for two years beyond the termination of the original lease terms. The option periods on all of the Unit 1 leases and one of the Unit 2 leases, amounting to 14% of the Unit 2 capacity under lease, may be further extended for up to an additional six years (the "Maximum Option Period") if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K, PNM notified each of the lessors of the Unit 1 leases that it will extend each Unit 1 lease for the Maximum Option Period upon the expiration of the basic lease term on January 15, 2015. In addition, PNM notified each of the lessors in the Unit 2 leases that PNM will "retain" the assets leased under that lease upon the expiration of the basic lease term on January 15, 2016. PNM will be required to specify by notice to each of the lessors by January 15, 2014, whether on January 15, 2016 it will extend the Unit 2 leases or purchase the leased assets. PNM is unable to predict the outcome or impact of these matters.

PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes, aggregate $52.6 million as of September 30, 2013 over the remaining original terms of the leases. Under certain circumstances (for example, final shutdown of the plant, 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 beneficial owners and take title to the leased interests. If such an event had occurred as of September 30, 2013, PNM could have been required to pay the beneficial owners up to $154.1 million, which would result in PNM taking ownership of the leased assets and termination of the leases. PNM has no other financial obligations or commitments to the trusts or the beneficial owners. 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 evaluated the PVNGS lease arrangements, including the notices discussed above, and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP. PNM has recorded no assets or liabilities related to the trusts other than the accrual of lease payments between the scheduled payment dates, which were $11.8 million at September 30, 2013 and $26.0 million at December 31, 2012, that are included in other current liabilities on the Condensed Consolidated Balance Sheets. For additional information regarding these leases, see Risk Factors, MD&A – Off Balance Sheet Arrangements and Note 7 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

Delta

PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. PNM also controls the dispatch of the generating plant, which impacts the variable payments made under the PPA and impacts the economic performance of the entity that owns Delta. PNM makes fixed and variable payments to Delta under the PPA. For the three and nine months ended September 30, 2013, PNM incurred fixed capacity charges of $1.6 million and $4.8 million and variable energy charges of $0.7 million and $1.3 million under the PPA. For the three and nine months ended September 30, 2012, PNM incurred fixed capacity charges of $1.6 million and $4.7 million and variable energy charges of $0.3 million and $0.6 million. PNM's only quantifiable obligation under the PPA is to make the fixed payments, which as of September 30, 2013, aggregated $40.7 million through the end of the PPA in 2020. PNM will also pay variable costs, which cannot be quantified since the amounts are based on how much the generating plant is in operation.

This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it is the primary beneficiary of the entity that owns Delta, or to consolidate that entity if it were determined that PNM is the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.

In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owns Delta. At closing PNM would make a cash payment of $23.0 million, which would be adjusted for actual working capital compared to a targeted working capital and certain prepayments of debt. Delta had project financing debt, which PNM would retire at closing of the purchase, of $16.9 million at September 30, 2013, including $3.2 million due by September 30, 2014. FERC approved the purchase on February 26, 2013 and the NMPRC approved the purchase on June 26, 2013. Closing is subject to the seller remedying specified operational, NERC compliance, and environmental issues, as well as other customary closing conditions. Closing of the purchase is anticipated to occur in early 2014.

Delta informed PNM that at September 30, 2013, it had total assets of $25.3 million, including net property, plant, and equipment of $21.0 million, and total liabilities of $18.9 million. Delta also indicated its revenue for the three and nine months ended September 30, 2013 was $2.8 million and $6.8 million and its net earnings were $0.6 million and $0.9 million. Consolidation of Delta would be immaterial to the Condensed Consolidated Balance Sheets of PNMR and PNM. Since all of Delta's revenues and expenses are attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Condensed Consolidated Statements of Earnings of PNMR and PNM would be to reclassify Delta's net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM.

XML

Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Allowance for uncollectible accounts	$ 1,391	$ 1,751
Accumulated depreciation, non-utility property	143	131
Accumulated depreciation, nuclear fuel	52,876	42,644
Cumulative preferred stock of subsidiary, stated value	$ 100	$ 100
Cumulative preferred stock of subsidiary, shares authorized	10,000,000	10,000,000
Cumulative preferred stock of subsidiary, shares issued	115,293	115,293
Cumulative preferred stock of subsidiary, shares authorized	115,293	115,293
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	79,653,624	79,653,624
Common stock, shares outstanding	79,653,624	79,653,624
Public Service Company of New Mexico [Member]
Allowance for uncollectible accounts	1,339	1,751
Accumulated depreciation, nuclear fuel	$ 52,876	$ 42,644
Cumulative preferred stock, stated value	$ 100	$ 100
Cumulative preferred stock, shares authorized	10,000,000	10,000,000
Cumulative preferred stock, shares issued	115,293	115,293
Cumulative preferred stock, shares outstanding	115,293	115,293
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares issued	39,117,799	39,117,799
Common stock, shares outstanding	39,117,799	39,117,799
Texas-New Mexico Power Company [Member]
Common stock, par value	$ 10	$ 10
Common stock, shares authorized	12,000,000	12,000,000
Common stock, shares issued	6,358	6,358
Common stock, shares outstanding	6,358	6,358

XML

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended
	May 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013
Income Tax Contingency [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, State and Local, Decrease				$ 1.5
New Mexico Corporate tax rate, current		7.60%
New Mexico Corporate tax rate, 2014		5.90%
Increase in regulatory liabilities due to change in state corporate tax rate		23.9
Increase in income tax expense due to change in state corporate tax rate			1.2
Additional Income Tax Expense, Impairment of NM Wind Credits			2.4
Federal Tax Refund	96.2
Public Service Company of New Mexico [Member]
Income Tax Contingency [Line Items]
Federal Tax Refund	77.4
PNMR to PNM [Member]
Income Tax Contingency [Line Items]
Federal Income Tax Refund Transferred to Related Party		$ 45.0

XML

Commitments and Contingencies (Commitments and Contingencies Related to the Environment) (Details) (USD $) In Millions, unless otherwise specified									12 Months Ended					12 Months Ended					9 Months Ended
	Dec. 21, 2011 mw	Dec. 21, 2011 San Juan Generating Station [Member]	Oct. 31, 2012 San Juan Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 San Juan Generating Station Units 2 and 3 [Member] PNM Electric [Member]	Nov. 08, 2010 Four Corners [Member]	Sep. 30, 2013 Clean Air Act related to Regional Haze [Member] state	Sep. 30, 2013 Clean Air Act Related to Post Combustion Controls [Member] Four Corners [Member] Public Service Company of New Mexico [Member]	Aug. 06, 2012 Clean Air Act Related to Post Combustion Controls [Member] Four Corners [Member] Public Service Company of New Mexico [Member] compliance_alternative	Sep. 30, 2012 Mercury Control [Member] San Juan Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Minimum [Member] San Juan Generating Station Units 1 and 4 [Member] Public Service Company of New Mexico [Member]	Jan. 31, 2010 Minimum [Member] San Juan Generating Station And Four Corners [Member] Public Service Company of New Mexico [Member] opp	Sep. 30, 2013 Maximum [Member] San Juan Generating Station Units 1 and 4 [Member] Public Service Company of New Mexico [Member]	Jan. 31, 2010 Maximum [Member] San Juan Generating Station And Four Corners [Member] Public Service Company of New Mexico [Member] opp	Sep. 30, 2012 Maximum [Member] Mercury Control [Member] San Juan Generating Station [Member] Public Service Company of New Mexico [Member]	Oct. 31, 2012 Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Minimum [Member] Clean Air Act, SNCR [Member] San Juan Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Minimum [Member] Clean Air Act, SNCR [Member] San Juan Generating Station Units 1 and 4 [Member] Public Service Company of New Mexico [Member]	Oct. 31, 2012 Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Maximum [Member] Clean Air Act, SNCR [Member] San Juan Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Maximum [Member] Clean Air Act, SNCR [Member] San Juan Generating Station Units 1 and 4 [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Environmental Protection Agency [Member] WildEarth Guardians filed an action to challenge EPA's rule in the Tenth Circuit [Member] San Juan Generating Station [Member]	Sep. 30, 2013 Environmental Protection Agency [Member] Clean Air Act Related to Post Combustion Controls [Member] Four Corners [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Nuclear Spent Fuel And Waste Disposal [Member] Other Deferred Credits [Member] Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2012 Nuclear Spent Fuel And Waste Disposal [Member] Other Deferred Credits [Member] Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]
Public Utilities, Commitments and Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss							$ 75.0														$ 42.8
Public Utilities, Number of Compliance alternatives								2
Public Utilities, Plant Requirement to Meet NOx emissions Limit							0.015
Public Utilities, Number of States To Address Regional Haze						50
Public Utilities, Potential to emit tons per year of visibility impairing pollution, maximum						250
Estimated Total Capital Cost If Requirement Occurred															824		910
Estimated Installation Capital Costs															85.0	60.0	90.0	80.0
Estimated Portion of Total Capital Costs if Requirement Occurred															105		110
Jointly Owned Utility Plant, Proportionate Ownership Share			46.30%							52.00%		55.00%
estimated cost of replacing gas fired peaking capacity due to retirement of SJGS units				299
Net book value				287
Public Utilities, Government Standard Emission Limit											0.060		0.070
Public Utilities, Plant Requirement to Meet Opacity Limit, Percentage							20.00%
Public Utilities, Rule Imposes Opacity Limitation on Certain Fugitive Dust Emissions From Coal and Material Handling Operations							20.00%
Current Annual Mercury Control Costs									0.6
Contingent Estimated Annual Mercury Control Cost														6.1
Minimum Megawatt Capacity from Coal and Oil-Fired Electric Generating Units under Jurisdiction of the Mercury and Air Toxics Standards	25
Mercury Removal Rate, Percentage		99.00%
Public Utilities, Proposed Seeking Shorter Compliance Period																			5 years
Public Utilities, Number of years after issuance of final determination to achieve compliance with requirements																				3 years
Loss Contingency Accrual, at Carrying Value																						$ 12.4	$ 13.9
Public Utilities, Jointly Owned Utility Plant, Sale of Ownership Percentage					48.00%

XML

Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2013

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

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,
	2013		2012		2013	2012
	(In thousands)
Services billings:
PNMR to PNM	$	22,241	$	22,143	65,729	68,030
PNMR to TNMP	6,731		6,439		20,948	20,206
PNM to TNMP	140		184		381	473
TNMP to PNMR	2		4		6	12
Interest billings:
PNMR to TNMP	139		22		354	72
PNMR to PNM	—		—		1	1
PNM to PNMR	35		45		113	134
Income tax sharing payments:
PNMR to PNM	—		—		45,000	63,114
PNMR to TNMP	—		—		—	1,952

XML

Regulatory and Rate Matters

9 Months Ended

Sep. 30, 2013

Regulatory and Rate Matters

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 10. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

PNM

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. The NMPRC requires renewable energy portfolios to be "fully diversified." Prior to December 2012, the diversity requirements were 20% from wind energy, 20% from solar energy, 10% from other renewable technologies, and 1.5% from distributed generation with the distributed generation component increasing to 3% in 2015. In December 2012, NMPRC issued an order that amended the diversity requirements to 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015, and adopted other changes to its renewable energy rule, including the increase in the RCT discussed below. In June 2013, the NMPRC initiated a new rulemaking proceeding in which it proposed to consider amending or eliminating specific diversity targets and to reconsider the inclusion of avoided environmental and capacity costs in the application of the RCT. A public hearing was held on September 10, 2013.

The REA provides for streamlined proceedings for approval of utilities' renewable energy procurement plans, assures utilities that they 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. The NMPRC had established a RCT for 2011 of 2% of all customers' aggregated overall annual electric charges that increased by 0.25% annually until reaching 3% in 2015. In December 2012, the NMPRC approved an amended RCT set at 3% of customers' annual electric charges beginning in 2013 and continuing thereafter.

In July 2011, PNM filed its renewable energy procurement plan for 2012. The plan requested a variance from the RPS due to RCT limitations. The plan was diversity-compliant based on the reduced RPS, except for non-wind/non-solar resources, which were not available. In December 2011, the NMPRC approved PNM's 2012 plan, but ordered PNM to spend an additional $0.9 million on renewable procurements in 2012. PNM is recovering the costs of the supplemental procurements through the renewable rider discussed below. The NMPRC also required PNM to file its 2013 renewable energy procurement plan by April 30, 2012. The 2013 plan proposed procurements for 2013 and 2014 of 20 MW of PNM-owned solar PV facilities, at an estimated cost of $45.5 million, wind and solar REC purchases in 2013, and a PPA for the output of a new 10 MW geothermal facility. The plan also included an additional procurement of 2 MW of PNM-owned solar PV facilities at an estimated cost of $4.5 million to supply the energy sold under PNM's voluntary renewable energy tariff. The plan will enable PNM to comply with the statutory RPS amount in 2013, but requires a variance from the NMPRC's diversity requirements in 2013 while the proposed geothermal facilities are being constructed. This plan had been expected to achieve full RPS quantity and diversity compliance by 2014 without exceeding the RCT. The NMPRC approved the plan in December 2012, but reduced the additional solar PV procurement from 2 MW to 1.5 MW. Construction of the geothermal facility has been delayed due to a longer than expected permitting process. PNM still anticipates that the facility will begin energy production January 1, 2014, but full-scale production will be delayed. PNM does not believe this delay will affect its ability to comply with the diversity requirements as amended in December 2012.

PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets the RPS quantity and diversity requirements within the RCT in 2014 and 2015. PNM's proposed procurements include 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of an existing 100 MW wind energy center beginning January 1, 2015 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015. A public hearing was held in October 2013. The NMPRC is required to approve or modify the plan within 180 days of the filing date. PNM cannot predict the outcome of this proceeding.

PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Riderbelow.

Renewable Energy Rider

On August 14, 2012, the NMPRC authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The approved rates are $0.0022335 per KWh in 2012 and $0.0028371 per KWh in 2013. The order disapproved the recovery of the cost of a supplemental REC procurement ordered by the NMPRC in the 2012 procurement plan case because the NMPRC had not yet acted on the specific $0.9 million procurement proposed by PNM, which is discussed under Renewable Portfolio Standard above. The NMPRC subsequently approved the supplemental REC procurement, but ordered that a hearing be held on its inclusion in the rider. Upon NMPRC approval, PNM implemented the rider on August 20, 2012. The rider will terminate upon a final order in PNM's next general rate case unless the NMPRC authorizes PNM to continue it. Amounts collected under the rider are capped at $18.0 million in 2012 and $24.6 million in 2013. Any amounts above the caps are deferred for future recovery without carrying costs. As a separate component of the rider, if PNM's earned return on jurisdictional equity in 2013, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM must refund to customers during May through December 2014 the amount over 10.5%.

In compliance with the NMPRC's rate rider order, PNM filed a notice to implement an increase in the current rider rate effective with May 2013 bills.  The NMPRC suspended the effective date of the new rate for a period of nine months from April 1, 2013 and appointed a Hearing Examiner to conduct a hearing on the proposed change.  On May 15, 2013, the NMPRC approved the requested increase. PNM implemented the new rate of $0.0030468 per KWh on May 28, 2013.

In its 2014 renewable energy procurement plan described above, PNM proposed to increase the rider rate to $0.0044391 effective January 1, 2014. PNM expects an order in this case in December 2013.

Energy Efficiency and Load Management

Program Costs

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

In October 2012, PNM filed an energy efficiency program application for programs to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive of $4.2 million and requested that the NMPRC issue an order by April 1, 2013. Portions of the program plan and proposed profit incentive are opposed by other parties to the case. PNM subsequently revised its proposed profit incentive to $2.9 million. After a hearing held in February 2013, the Hearing Examiner recommended approval of the programs as proposed and recommended an annual incentive of $1.7 million. The NMPRC has not yet acted on the Hearing Examiner's recommendations. PNM is not able to predict the outcome of this matter.

Disincentives/Incentives Adder

The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. A rule approved by the NMPRC authorized electric utilities to collect rate adders of $0.01 per KWh for lifetime energy savings and $10 per KW for demand savings related to energy efficiency and demand response programs beginning in 2010. The NMAG and NMIEC appealed the NMPRC order adopting this rule to the New Mexico Supreme Court. PNM began implementing a rate rider under the rule to collect adders related to its 2010 program savings in December 2010 while the appeal of the rule was pending. In July 2011, the Supreme Court annulled and vacated the order adopting the rule and remanded the matter to the NMPRC. As a result of the Supreme Court decision, PNM filed revised tariffs and ceased collecting this adder for 2010 program savings on August 21, 2011. Of the $4.2 million authorized for recovery, $2.6 million was collected through August 20, 2011.

In June 2011, prior to the Supreme Court decision, the NMPRC approved PNM-specific adders of $0.002 per KWh and $4 per KW for savings due to programs implemented in 2011. PNM is presently collecting $1.3 million in adder revenues consistent with this order. After the Supreme Court decision vacating the rule, the NMPRC initiated a proceeding to determine whether PNM should be required to cease collecting the adders and to refund all adder revenues collected since December 2010. In November 2011, the NMPRC issued orders that PNM is not required to refund any adder revenues and is authorized to continue collecting the adders. However, in an order on rehearing, which it subsequently rescinded, the NMPRC further reduced the amount of the authorized adders. Prior to the rescission, PNM appealed the rehearing order to the Supreme Court. In March 2012, the Supreme Court granted PNM's motion to vacate the rehearing order and dismiss PNM's appeal. In a separate appeal and writ proceeding in the Supreme Court, NMIEC and the NMAG sought to overturn the NMPRC order allowing PNM to continue to collect adders in light of the 2011 Supreme Court decision. On May 21, 2012, the Supreme Court dismissed the writ proceeding. On September 20, 2013, the Supreme Court issued a decision in the NMIEC and NMAG appeal. The Supreme Court affirmed the NMPRC's decision authorizing the incentive and remanded the case to the NMPRC. On October, 2, 2013, the NMPRC closed the docket.

On March 27, 2013, PNM filed its reconciliation for actual energy efficiency program costs, associated incentives, and actual collections for calendar year 2012. The reconciliation filing showed a net over-recovery of $0.2 million, composed of an over-recovery of $1.0 million of program costs and an under-recovery of incentives of $0.8 million. PNM subsequently revised the estimated incentive under-recovery to $0.5 million. PNM and the NMPRC staff filed a motion seeking to substitute the new reconciliation filing with a proposed effective date of May 28, 2013. On April 24, 2013, the NMPRC issued an order granting the motion. PNM implemented the new rate on May 28, 2013.

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 from the rates charged on a per KWh of consumption, as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement the New Mexico Efficient Use of Energy Act. Included in the proposed rule is a provision that would limit incentive awards to an amount equal to the product (expressed in dollars) of the utility's weighted cost of capital (expressed as a percent) and its approved annual program costs. The NOPR establishes a schedule for comments and sets a public hearing in November 2013.

2010 Electric Rate Case and FPPAC

An order of the NMPRC approving an amended stipulation in PNM's 2010 Electric Rate Case limits the amount that can be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs during certain years. Costs in excess of the limits are deferred, without carrying costs, for recovery in future periods. The fuel cost caps are $38.8 million for the FPPAC year beginning July 1, 2012, which PNM began collecting at that time, and $36.2 million for the FPPAC year beginning July 1, 2013. PNM estimates that the caps will result in approximately $38.4 million of FPPAC costs being deferred for future collection at June 30, 2014. The portion of the costs and insurance recovery attributable to customers covered by the FPPAC resulting from the mine fire incident discussed in Note 10 are included in the FPPAC amounts.

Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On May 28, 2013, PNM filed the required continuation application and requested that its current FPPAC be modified to increase the reset frequency of the fuel factor from annually to quarterly, to allow PNM to retain 10% of its off-system sales margin, and to apply the same carrying charge rate to either over or under-collections in the balancing account. A hearing has been scheduled to begin on December 10, 2013. PNM is unable to predict the outcome of this proceeding.

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. In its most recent IRP, which was filed in July 2011, PNM indicated that it planned to meet its anticipated load growth through a combination of new natural gas-fired generating plants, renewable energy resources, load management, and energy efficiency programs. As required by NMPRC rules, PNM utilized a public advisory group process during the development of the 2011 IRP. Two protests were filed to the IRP requesting rejection of the plan. The NMPRC assigned the case to a Hearing Examiner and designated a mediator to facilitate negotiations. The NMPRC staff filed a motion in December 2011 to dismiss the protests and terminate the proceeding on the ground that PNM's IRP fully complies with NMPRC rules. On September 18, 2013, the NMPRC issued an order that closed this docket.

Consistent with the NMPRC's IRP rule, PNM has initiated the process to prepare its 2014 IRP. Initial public participation meetings have been held. The 2014 IRP is scheduled to be filed at the NMPRC by June 30, 2014.

Emergency FPPAC

In 2008, the NMPRC authorized PNM to implement an Emergency FPPAC from June 2, 2008 through June 30, 2009. The NMPRC order approving the Emergency FPPAC also provided that if PNM's base load generating units did not operate at or above a specified capacity factor and PNM was required to obtain replacement power to serve jurisdictional customers, PNM would be required to make a filing with the NMPRC seeking approval of the replacement power costs. In its required filing, PNM stated that the costs of the replacement power amounting to $8.0 million were prudently incurred and made a motion that they be approved. The NMPRC staff opposed PNM's motion and recommended that PNM be required to refund the amount collected. Auditors selected by the NMPRC found that PNM was prudent in operating its base load units and in securing replacement power but had not obtained prior NMPRC approval in the manner required by the NMPRC order. PNM continues to assert that its recovery of replacement power costs was proper and did not violate the NMPRC's order. The NMPRC has not ruled on this matter. Under the terms of the approved stipulation in the 2010 Electric Rate Case, the parties to the stipulation, including the NMPRC staff, jointly requested that the NMPRC take no further action in this matter and close the docket. No party opposed that request. Although the NMPRC has not acted on the joint request, the NMPRC electronic docket shows the docket closed.

Applications for Approvals to Purchase Delta

As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K, PNM has entered in to an agreement to purchase Delta, a 132 MW natural gas peaking unit from which PNM currently acquires energy and capacity under a PPA. The agreement to purchase Delta required approvals by the NMPRC and FERC. On January 3, 2013, PNM filed an application with the NMPRC for a CCN to own and operate Delta and for a determination of related ratemaking principles and treatment. On June 26, 2013, the NMPRC granted PNM's CCN application and approved PNM's proposed ratemaking treatment. PNM filed an application for approval of the Delta acquisition at FERC on January 24, 2013. FERC approved the purchase on February 26, 2013. Closing on the purchase is anticipated in early 2014.

Application for Approval of La Luz Generating Station

On May 17, 2013, PNM filed an application with the NMPRC for a CCN to construct, own, and operate a 40 MW gas-fired generating facility near Belen, New Mexico. The application also requests a determination of related ratemaking principles and treatment. The facility is expected to cost approximately $63.2 million and go into service in the first quarter of 2016. PNM has entered into a contract for purchase of the turbine to be used for this project and a separate contract for the construction of the facility on a turn-key basis. Both contracts allow PNM to cancel if NMPRC approval is not obtained. A hearing on PNM's application is scheduled to begin on April 8, 2014. PNM is unable to predict the outcome of this matter.

San Juan Generating Station Units 2 and 3 Retirement

PNM anticipates filing an application at the NMPRC to retire SJGS Units 2 and 3, as discussed in Note 10, before the end of 2013. In the same application, PNM will also seek approval to recover its remaining costs in SJGS 2 and 3 and for a CCN for some of the resources to replace the retired units, which PNM anticipates will include PNM's share of PVNGS Unit 3 and additional capacity in SJGS Unit 4. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements.

Transmission Rate Case

In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually, based on a return on equity of 12.25%. The filing also sought to revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms.  In December 2010, FERC issued an order accepting PNM's filing and suspending the proposed tariff revisions for five months. The proposed rates were implemented on June 1, 2011, subject to refund. The rate increase applied to all of PNM's wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM's transmission system to transmit power at the wholesale level.  The rate increase did not impact PNM's retail customers. On January 2, 2013, FERC approved an unopposed settlement agreement, which increases transmission service revenues by $2.9 million annually. In addition, the parties agreed that if PNM files for a formula based rate change within one year from FERC's approval of the settlement agreement, no party will oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM refunded amounts collected in excess of the settled rates in January 2013 concluding this matter.

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. The rates resulting from PNM's application are intended to replace the rates approved by the FERC on January 2, 2013 in the transmission rate case discussed above. As filed, PNM's request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM's 2011 data and a 10.81% return on equity, and authority to adjust transmission rates annually based on an approved formula. The proposed $3.2 million rate increase would be in addition to the $2.9 million rate increase approved by the FERC on January 2, 2013.

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 return-on-equity ("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. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC's order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC on January 2, 2013. The new rates will apply to all of PNM's wholesale electric transmission service customers. The new rates will not apply to PNM's retail customers. On June 10, 2013, FERC denied PNM's motion for rehearing regarding FERC's order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding.

Tri-State Complaint

On March 13, 2013, Tri-State filed a complaint with FERC alleging that PNM's existing transmission rates approved by FERC on January 2, 2013 in the transmission rate case discussed above are unjust and unreasonable under the Federal Power Act.  Tri-State's allegations were premised upon FERC's March 1, 2013 order and certain data provided by PNM in PNM's Formula Transmission Rate Case discussed above.  Tri-State sought a reduction in PNM's annual transmission revenue requirement for the period between March 13, 2013 and the implementation of PNM's proposed rates under the Formula Transmission Rate Case.  Tri-State also requested that FERC consolidate the complaint proceeding with the Formula Transmission Rate Case.  On April 2, 2013, PNM answered Tri-State's complaint, asking FERC to dismiss the complaint and deny Tri-State's request to consolidate the complaint proceeding with the Formula Transmission Rate Case. On June 10, 2013, FERC dismissed Tri-State's complaint and denied Tri-State's request to consolidate the complaint proceeding with the PNM FERC Transmission Formula Rate Case. This matter is now concluded.

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc. Rate Case

In September 2011, PNM filed an unexecuted amended sales agreement between PNM and NEC with FERC. The agreement proposed a cost of service based rate for the electric service and ancillary services PNM provides to NEC, which would result in an annual increase of $8.7 million or a 39.8% increase over existing rates. PNM also requested a FPPAC and full recovery of certain third-party transmission charges PNM incurs to serve NEC. NEC filed a protest to PNM's filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and PNM filed for the necessary FERC approval on December 6, 2012. The settlement agreement would result in an annual increase of $5.3 million, an extension of the contract for 10 years, and an agreement that PNM will be able to file an application for formula based rates to be effective in 2015. On April 5, 2013, FERC approved the settlement agreement. PNM has refunded the amounts collected in excess of the settled rates concluding this matter.

City of Gallup, New Mexico Contract Approval Case

PNM provides both energy and power services to Gallup, PNM's second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On May 1, 2013, PNM requested FERC approval of the amended agreement to be effective July 1, 2013. On June 21, 2013, FERC approved the amended agreement. Revenue from Gallup will increase by $3.1 million during the term of the amended agreement. On September 26, 2013, Gallup issued a request for proposals for long term power supply. Proposals are due November 26, 2013. PNM anticipates submitting a proposal, but is unable to predict if services provided to Gallup will continue upon expiration of the amended agreement.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.3 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 and is scheduled to be completed over a 5-year period.

In February 2012, the PUCT opened a proceeding to consider the feasibility of an "opt-out" program for retail consumers that wish to decline receipt of an advanced meter. The PUCT has requested comments and convened a public meeting to hear various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012.

On February 21, 2013, the PUCT filed a proposed rule to permit customers to opt-out of the AMS deployment. 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 will be borne by opt-out customers through an initial fee and ongoing monthly charge. All transmission and distribution utilities in ERCOT are required to initiate proceedings to establish these charges.

On September 30, 2013, TNMP filed an application to set the initial fee and monthly charges to be assessed for non-standard metering service provided to those retail customers who choose to decline the advanced meter necessary for standard metering service. TNMP's filing seeks recovery of $0.2 million through proposed initial fees ranging from $142.84 to $247.48. An additional $0.5 million in ongoing expenses would be recovered via a proposed monthly charge of $38.99. As the proceeding has just been initiated, TNMP cannot predict the outcome of this proceeding although TNMP does not expect it to have a material impact on its financial position, results of operations, or cash flows.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor. On August 28, 2012, the PUCT approved a settlement that permits TNMP to collect estimated 2013 program costs of $4.8 million, plus recovery of an aggregate of $0.4 million in under-collected costs from prior years, case expenses, and a performance bonus for 2011. TNMP's new rates were effective January 1, 2013. On May 15, 2013, TNMP filed its 2014 energy efficiency cost recovery factor application with the PUCT. The application seeks approval to collect $5.6 million, which includes $4.7 million in estimated program expenses for 2014, a $0.7 million performance bonus for 2012, a refund of $0.1 million over collection of energy savings expenses for the 2012 program year, and case expenses. In July 2013, the parties filed a settlement to permit TNMP to collect the substantially all of the requested $5.6 million. The settlement was approved by the PUCT on October 25, 2013.

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.

On January 31, 2013, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base was $21.9 million, which would increase revenues $2.9 million annually. On March 19, 2013, the PUCT ALJ approved TNMP's interim transmission cost of service filing and rates went into effect with bills rendered March 20, 2013. On August 1, 2013, TNMP filed an application to further update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $18.1 million, which would increase revenues by $2.8 million annually. The PUCT ALJ approved TNMP's interim transmission cost of service filing and rates went into effect with bills rendered on September 17, 2013.

Consolidated Tax Savings Adjustment

On June 14, 2013, the Governor of Texas signed into law a bill eliminating the consolidated tax savings adjustment ("CTSA") from electric utility ratemaking in Texas. Previously, the CTSA required electric utilities to artificially reduce their respective tax expenses due to the losses incurred by their affiliates. The bill became effective on September 1, 2013.

XML

Stock-Based Compensation

9 Months Ended

Sep. 30, 2013

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"). In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted in 2013 or 2012 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets and have service requirements. 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 2012 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, certain 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 stock awards.

The stock-based compensation expense related to stock options and restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However, compensation expense for awards to participants that are retirement eligible on the award date is recognized immediately at the award date and is not amortized. 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, 2013 and December 31, 2012, PNMR had unrecognized expense related to stock awards of $5.7 million and $3.8 million. 

The Company uses the Black Scholes option pricing model to estimate the fair value of stock option awards based on multiple factors, including historical exercise patterns of employees in relatively homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected exercising patterns for these same homogeneous groups, and both the implied and historical volatility of PNMR's stock price. 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 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.

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	2013			2012
Expected quarterly dividends per share	$	0.165		$	0.145
Risk-free interest rate	0.34		%	0.65		%
Market-Based Shares
Dividend yield	2.86		%	3.45		%
Expected volatility	25.11		%	43.98		%
Risk-free interest rate	0.36		%	1.04		%

The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the nine months endedSeptember 30, 2013:

	Stock Option Shares		Weighted- Average Exercise Price		Restricted Stock		Weighted- Average Grant Date Fair Value
Outstanding at beginning of period	1,992,700		$	20.72	353,722		$	14.03
Granted	—		$	—	249,113		$	20.03
Exercised	(260,579	)	$	13.43	(275,988	)	$	15.92
Forfeited	—		$	—	(8,366	)	$	18.37
Expired	(292,644	)	$	27.23	—		$	—
Outstanding at end of period	1,439,477		$	20.72	318,481		$	17.88

Included as restricted stock granted and exercised in the table above are 100,953 shares that were based upon achieving performance or market targets for 2012. The Board approved these shares in February 2013, including shares with market targets at near maximum levels.

PNMR also has share agreements that provide for performance or market targets through 2015. Excluded from the above table are maximums of 188,129, 198,369, and 179,811 restricted stock shares for periods ending in 2013, 2014, and 2015 that would be awarded if all performance or market criteria are achieved 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 the Company meets specific market targets at the end of 2016 and she remains an employee of the Company. If the Company achieves specific market targets at the end of 2014 and she remains an employee of the Company, she would receive 35,000 of the total shares at that time. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include any shares under the retention award agreement.

At September 30, 2013, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.7 million with a weighted-average remaining contract life of 3.56 years. At September 30, 2013, the exercise price of 793,010 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

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

	Nine Months Ended September 30,
Stock Options	2013		2012
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	625	$	1,058
Total intrinsic value of options exercised (in thousands)	$	2,466	$	4,515
Restricted Stock
Weighted-average grant date fair value	$	20.03	$	15.63
Total fair value of restricted shares that vested (in thousands)	$	4,395	$	4,755

XML

Goodwill

9 Months Ended

Sep. 30, 2013

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 June 6, 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 in 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 the annual evaluation performed as of April 1, 2013, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit. For the PNM reporting unit, 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, 2013 and 2012 did not indicate impairments of the goodwill of any of PNMR's reporting units. The April 1, 2013 and 2012 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by more than 10%. The April 1, 2012 quantitative evaluation indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by more than 10%. Since the April 1, 2013 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 22 of Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K.

XML

Related Party Transactions

9 Months Ended

Sep. 30, 2013

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,
	2013		2012		2013	2012
	(In thousands)
Services billings:
PNMR to PNM	$	22,241	$	22,143	65,729	68,030
PNMR to TNMP	6,731		6,439		20,948	20,206
PNM to TNMP	140		184		381	473
TNMP to PNMR	2		4		6	12
Interest billings:
PNMR to TNMP	139		22		354	72
PNMR to PNM	—		—		1	1
PNM to PNMR	35		45		113	134
Income tax sharing payments:
PNMR to PNM	—		—		45,000	63,114
PNMR to TNMP	—		—		—	1,952

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 25, 2013
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, 2013
Document Fiscal Year Focus	2013
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

Income Taxes

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

As required under GAAP, the Company makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. Year-to-date income tax expense is then calculated by applying the anticipated annual effective tax rate to year-to-date earnings before taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, as well as adjustments due to enactment of new tax laws, be excluded from the estimated annual effective tax rate calculation.

On January 3, 2013, the American Taxpayer Relief Act of 2012, which extended fifty percent bonus depreciation, was signed into law.  Due to provisions in the act, taxes payable to the State of New Mexico for 2013 were reduced, which resulted in an impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR was required to record this impairment, which after federal income tax benefit, amounted to $1.5 million as additional income tax expense during the three months ended March 31, 2013. This impairment is reflected in PNMR's Corporate and Other segment.

On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction will be 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. 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. The increase in the regulatory liability was $23.9 million. The portion of the adjustment that is not related to PNM's regulated activities was recorded as a reduction in deferred tax assets and an increase in income tax expense of $1.2 million during the three months ended June 30, 2013. This additional income tax expense is reflected in PNMR's Corporate and Other segment.

The future reduction in taxes payable to the State of New Mexico resulting from the rate reduction in House Bill 641 and revisions in estimates of future taxable income resulted in a further impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR was required to record this impairment, which after federal income tax benefit, amounted to $2.4 million as additional income tax expense during the three months ended June 30, 2013. This impairment is reflected in PNMR's Corporate and Other segment.

On April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for electric generation property.  Adoption of the safe harbor method is elective for years ending on or after December 31, 2012.  On July 11, 2013, the IRS issued a directive that suspends most current examination activity related to generation repairs methodology for any company that is eligible for the safe harbor. PNM is evaluating the possible effects of adopting the safe harbor method and the ultimate outcome cannot be determined at this time although the effects are not expected to be material.

In May 2013, PNMR received a refund of federal income taxes paid in prior years, which primarily was due to bonus tax depreciation and changes in the Company's method of accounting for repairs expense for income tax purposes. The total refund was $96.2 million of which $77.4 million was attributable to PNM. As of September 30, 2013, $45.0 million had been transferred to PNM.

On September 13, 2013, the IRS issued final regulations addressing the recovery of amounts paid to acquire, produce, or improve tangible personal property and the accounting for and retirement of depreciable property. Also issued were proposed regulations addressing dispositions of property. Repairs of electric transmission and distribution property and repairs of electric generation property are specifically addressed in other Revenue Procedures issued by the IRS. The effects of the remainder of regulations are being evaluated by the Company and cannot be determined at this time. However, due to PNMR's net operating loss carryforward position for income tax purposes, the effects are not expected to be material.