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, 2011

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)
	Alvarado Square
	Albuquerque, New Mexico 87158
	(505) 241-2700
001-06986	Public Service Company of New Mexico	85-0019030
	(A New Mexico Corporation)
	Alvarado Square
	Albuquerque, New Mexico 87158
	(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 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 November 1, 2011, 86,673,174 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 November 1, 2011 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 November 1, 2011 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.

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 Balance Sheets	8
Condensed Consolidated Statements of Cash Flows	10
Condensed Consolidated Statements of Changes in Equity	12
Condensed Consolidated Statements of Comprehensive Income	13
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	14
Condensed Consolidated Balance Sheets	15
Condensed Consolidated Statements of Cash Flows	17
Condensed Consolidated Statements of Changes in Equity	19
Condensed Consolidated Statements of Comprehensive Income	20
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	21
Condensed Consolidated Balance Sheets	22
Condensed Consolidated Statements of Cash Flows	24
Condensed Consolidated Statements of Changes in Equity	26
Condensed Consolidated Statements of Comprehensive Income	27
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	28
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	73
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	95
ITEM 4. CONTROLS AND PROCEDURES	99
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	100
ITEM 1A. RISK FACTORS	101
ITEM 5. OTHER INFORMATION	102
ITEM 6. EXHIBITS	102
SIGNATURE	104

3

GLOSSARY

Definitions:
Afton	Afton Generating Station
ABCWUA	Albuquerque Bernalillo County Water Utility Authority
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
AOCI	Accumulated Other Comprehensive Income
APS	Arizona Public Service Company, which is the operator and a co-owner of PVNGS and   Four Corners
ARO	Asset Retirement Obligation
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
Cascade	Cascade Investment, L.L.C.
CCB	Coal Combustion Byproducts
CO2	Carbon Dioxide
CTC	Competition Transition Charge
Decatherm	Million BTUs
Delta	Delta-Person Generating Station
DOA	United States Department of Agriculture
DOE	United States Department of Energy
DOI	United States Department of Interior
ECJV	ECJV Holdings, LLC
EIB	New Mexico Environmental Improvement Board
EIP	Eastern Interconnection Project
EnergyCo	EnergyCo, LLC, a limited liability company, owned 50% by each of PNMR and ECJV; now known as Optim Energy
EPA	United States Environmental Protection Agency
EPE	El Paso Electric
ERCOT	Electric Reliability Council of Texas
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
GEaR	Gross Earnings at Risk
GHG	Greenhouse Gas Emissions
GWh	Gigawatt hours
IRP	Integrated Resource Plan
KW	Kilowatt
KWh	Kilowatt Hour
LIBOR	London Interbank Offered Rate
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
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
NERC	North American Electric Reliability Corporation
NMAG	New Mexico Attorney General
NMED	New Mexico Environment Department
NMIEC	New Mexico Industrial Energy Consumers Inc.
NMPRC	New Mexico Public Regulation Commission
NOI	Notice of Intent
NOx	Nitrogen Oxides
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
NSR	New Source Review
O&M	Operations and Maintenance
OCI	Other Comprehensive Income
Optim Energy	Optim Energy, LLC, a limited liability company, owned 50% by each of PNMR and ECJV; formerly known as EnergyCo
OSM	United States Office of Surface Mining Reclamation and Enforcement
PCRBs	Pollution Control Revenue Bonds
PNM	Public Service Company of New Mexico and Subsidiaries
PNM Facility	PNM’s Unsecured Revolving Credit Facility
PNM Revolving Credit Facility	PNM’s $400.0 Million Unsecured Revolving Credit Facility
PNMR	PNM Resources, Inc. and Subsidiaries
PNMR Facility	PNMR’s Unsecured Revolving Credit Facility
PNMR Revolving Credit Facility	PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PPA	Power Purchase Agreement
PRP	Potential Responsible Party
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
RFP	Request for Proposal
RMC	Risk Management Committee
RPS	Renewable Energy Portfolio Standard
SCE	Southern California Edison Company
SEC	United States Securities and Exchange Commission
SIP	State Implementation Plan
SJCC	San Juan Coal Company
SJGS	San Juan Generating Station
SO2	Sulfur Dioxide
SPS	Southwestern Public Service Company
SRP	Salt River Project

5

S&P	Standard and Poor’s Ratings Services
TECA	Texas Electric Choice Act
TNMP	Texas-New Mexico Power Company and Subsidiaries
TNMP Revolving Credit Facility	TNMP’s $75 Million Revolving Credit Facility
Valencia	Valencia Energy Facility
VaR	Value at Risk
WACC	Weighted Average Cost of Capital

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,
	2011			2010			2011			2010
	(In thousands, except per share amounts)
Electric Operating Revenues	$	549,498		$	503,653		$	1,352,747		$	1,292,865
Operating Expenses:
Cost of energy	250,854			215,169			582,814			557,238
Administrative and general	69,755			71,193			197,016			196,398
Energy production costs	39,730			42,306			135,510			148,002
Regulatory disallowances	—			—			21,402			—
Depreciation and amortization	42,370			38,980			119,115			113,634
Transmission and distribution costs	17,925			15,012			52,962			44,574
Taxes other than income taxes	20,580			15,585			50,564			43,456
Total operating expenses	441,214			398,245			1,159,383			1,103,302
Operating income	108,284			105,408			193,364			189,563
Other Income and Deductions:
Interest income	3,748			4,499			12,010			14,608
Gains (losses) on investments held by NDT	(4,109		)	2,206			7,688			2,606
Other income	1,755			1,963			3,559			13,333
Equity in net earnings (loss) of Optim Energy	—			2,495			—			(5,714		)
Other deductions	(4,685		)	(3,848		)	(11,638		)	(8,861		)
Net other income (deductions)	(3,291		)	7,315			11,619			15,972
Interest Charges	31,124			31,317			92,251			94,488
Earnings before Income Taxes	73,869			81,406			112,732			111,047
Income Taxes	25,964			28,813			37,206			37,365
Net Earnings	47,905			52,593			75,526			73,682
(Earnings) Attributable to Valencia Non-controlling Interest	(4,111		)	(3,909		)	(10,764		)	(10,305		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Net Earnings Attributable to PNMR	$	43,662		$	48,552		$	64,366		$	62,981
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.48		$	0.53		$	0.70		$	0.69
Diluted	$	0.48		$	0.53		$	0.70		$	0.69
Dividends Declared per Common Share	$	0.125		$	0.125		$	0.375		$	0.375

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

7

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011		December 31, 2010
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	22,298	$	15,404
Accounts receivable, net of allowance for uncollectible accounts of $1,645 and $11,178	107,637		97,245
Unbilled revenues	47,793		71,453
Other receivables	46,955		60,562
Materials, supplies, and fuel stock	53,092		52,479
Regulatory assets	28,693		36,292
Commodity derivative instruments	3,716		15,999
Income taxes receivable	99,506		97,450
Current portion of accumulated deferred income taxes	886		886
Current assets of business unit held for sale	166,119		—
Other current assets	49,043		96,110
Total current assets	625,738		543,880
Other Property and Investments:
Investment in PVNGS lessor notes	79,390		103,871
Investments held by NDT	157,001		156,922
Other investments	14,639		18,791
Non-utility property, net of accumulated depreciation of $125 and $2,307	5,139		7,333
Total other property and investments	256,169		286,917
Utility Plant:
Plant in service and plant held for future use	4,998,685		4,860,614
Less accumulated depreciation and amortization	1,686,971		1,626,693
	3,311,714		3,233,921
Construction work in progress	159,918		137,622
Nuclear fuel, net of accumulated amortization of $36,722 and $26,247	78,218		72,901
Net utility plant	3,549,850		3,444,444
Deferred Charges and Other Assets:
Regulatory assets	475,937		502,467
Goodwill	278,297		321,310
Other intangible assets, net of accumulated amortization of none and $5,414	—		26,425
Commodity derivative instruments	247		5,264
Non-current assets of business unit held for sale	101,059		—
Other deferred charges	85,343		94,376
Total deferred charges and other assets	940,883		949,842
	$	5,372,640	$	5,225,083

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

8

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	289,000		$	222,000
Current installments of long-term debt	2,252			2,252
Accounts payable	71,949			95,969
Accrued interest and taxes	82,636			47,783
Regulatory liabilities	429			724
Commodity derivative instruments	1,746			31,407
Dividends declared	10,966			11,565
Liability for purchase of Series A Preferred Stock	73,475			—
Current liabilities of business unit held for sale	103,915			—
Other current liabilities	76,281			108,424
Total current liabilities	712,649			520,124
Long-term Debt	1,564,077			1,563,595
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	582,485			540,106
Accumulated deferred investment tax credits	16,350			18,089
Regulatory liabilities	363,087			342,465
Asset retirement obligations	77,290			76,637
Accrued pension liability and postretirement benefit cost	227,401			270,172
Commodity derivative instruments	1,913			12,831
Non-current liabilities of business unit held for sale	17,596			—
Other deferred credits	123,054			147,616
Total deferred credits and other liabilities	1,409,176			1,407,916
Total liabilities	3,685,902			3,491,635
Commitments and Contingencies (See Note 9)
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 Convertible Preferred Stock, Series A without mandatory redemption requirements (no stated value, 10,000,000 shares authorized: issued and outstanding none and 477,800 shares)	—			100,000
PNMR common stockholders’ equity:
Common stock outstanding (no par value, 120,000,000 shares authorized: issued and outstanding 86,673,174 shares)	1,318,539			1,290,465
Accumulated other comprehensive income (loss), net of income taxes	(72,913		)	(68,666		)
Retained earnings	345,614			314,943
Total PNMR common stockholders’ equity	1,591,240			1,536,742
Non-controlling interest in Valencia	83,969			85,177
Total equity	1,675,209			1,721,919
	$	5,372,640		$	5,225,083

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,
	2011			2010
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	75,526		$	73,682
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	151,984			138,013
PVNGS firm-sales contract revenue	(2,558		)	(43,535		)
Bad debt expense	20,120			21,023
Deferred income tax expense	43,167			23,276
Equity in net (earnings) loss of Optim Energy	—			5,714
Net unrealized (gains) losses on derivatives	(5,869		)	41,649
Realized (gains) on investments held by NDT	(7,688		)	(2,606		)
Stock based compensation expense	4,302			2,525
Regulatory disallowances	21,402			—
Other, net	3,549			3,820
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(88,462		)	(44,710		)
Materials, supplies, and fuel stock	(985		)	(2,557		)
Other current assets	(2,901		)	(54,654		)
Other assets	(3,310		)	(4,781		)
Accounts payable	13,781			(9,380		)
Accrued interest and taxes	33,049			141,478
Other current liabilities	(12,919		)	(47,201		)
Other liabilities	(43,691		)	(25,198		)
Net cash flows from operating activities	198,497			216,558
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(236,275		)	(181,340		)
Proceeds from sales of investments held by NDT	121,202			57,098
Purchases of investments held by NDT	(122,174		)	(59,395		)
Return of principal on PVNGS lessor notes	32,274			29,851
Investments in Optim Energy	—			(17,610		)
Other, net	145			636
Net cash flows from investing activities	(204,828		)	(170,760		)

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

10

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	67,000			(6,000		)
Long-term borrowings	50,000			403,845
Repayment of long-term debt	(50,000		)	(403,845		)
Proceeds from stock option exercise	2,570			1,117
Purchases to satisfy awards of common stock	(5,288		)	(2,804		)
Excess tax (shortfall) from stock-based payment arrangements	—			(264		)
Dividends paid	(34,690		)	(34,691		)
Equity transactions with Valencia’s owner	(11,972		)	(11,149		)
Payments received on PVNGS firm-sales contracts	2,558			22,872
Proceeds from transmission interconnection agreements	1,246			—
Repayment of transmission interconnection agreements	(4,637		)	—
Debt issuance costs and other	(100		)	(4,423		)
Net cash flows from financing activities	16,687			(35,342		)
Change in Cash and Cash Equivalents	10,356			10,456
Cash and Cash Equivalents at Beginning of Period	15,404			14,641
Cash and Cash Equivalents at End of Period	$	25,760		$	25,097
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	64,130		$	67,824
Income taxes paid (refunded), net	$	(3,744	)	$	(98,792	)
Supplemental schedule of noncash financing activities:
Liability incurred for purchase of Convertible Preferred Stock, Series A	$	73,475

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

11

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

	Attributable to PNMR															Non- controlling Interest in Valencia
	Preferred Stock, Series A			PNMR Common Stockholders’ Equity
				Common Stock			AOCI			Retained Earnings			Total						Total Equity
	(In thousands)
Balance at December 31, 2010	$	100,000		$	1,290,465		$	(68,666	)	$	314,943		$	1,536,742		$	85,177		$	1,721,919
Proceeds from stock option exercise	—			2,570			—			—			2,570			—			2,570
Purchases to satisfy awards of common stock	—			(5,288		)	—			—			(5,288		)	—			(5,288		)
Stock based compensation expense	—			4,302			—			—			4,302			—			4,302
Valencia’s transactions with its owner	—			—			—			—			—			(11,972		)	(11,972		)
Net earnings before subsidiary preferred stock dividends	—			—			—			64,762			64,762			10,764			75,526
Subsidiary preferred stock dividends	—			—			—			(396		)	(396		)	—			(396		)
Purchase of preferred stock	(100,000		)	26,490			—			—			26,490			—			(73,510		)
Total other comprehensive income (loss)	—			—			(4,247		)	—			(4,247		)	—			(4,247		)
Dividends declared on common stock	—			—			—			(33,695		)	(33,695		)	—			(33,695		)
Balance at September 30, 2011	$	—		$	1,318,539		$	(72,913	)	$	345,614		$	1,591,240		$	83,969		$	1,675,209

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

12

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In thousands)
Net Earnings	$	47,905		$	52,593		$	75,526		$	73,682
Other Comprehensive Income (Loss):
Unrealized Gain (Loss) on Investment Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit of $1,123, $(4,270), $(8,157), and $(4,212)	(1,713		)	6,516			12,448			6,428
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,593, $1,145, $11,555, and $2,475	(2,431		)	(1,747		)	(17,632		)	(3,776		)
Pension liability adjustment, net of income tax (expense) benefit of $(425), $0, $176 and $147	648			—			(318		)	(223		)
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $123, $(906), $441, and $(4,765)	(219		)	1,267			(781		)	6,906
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(827), $5,319, $(1,129), and $13,546	1,493			(8,026		)	2,036			(20,396		)
Total Other Comprehensive Income (Loss)	(2,222		)	(1,990		)	(4,247		)	(11,061		)
Comprehensive Income	45,683			50,603			71,279			62,621
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,111		)	(3,909		)	(10,764		)	(10,305		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Comprehensive Income Attributable to PNMR	$	41,440		$	46,562		$	60,119		$	51,920

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,
	2011			2010			2011			2010
	(In thousands)
Electric Operating Revenues	$	323,760		$	304,268		$	797,232		$	777,864
Operating Expenses:
Cost of energy	108,708			98,030			279,419			264,102
Administrative and general	37,916			42,107			110,833			117,291
Energy production costs	39,730			42,306			135,510			148,000
Regulatory disallowances	—			—			17,479			—
Depreciation and amortization	25,058			23,111			71,691			68,887
Transmission and distribution costs	11,848			9,819			35,357			29,450
Taxes other than income taxes	12,586			8,220			30,323			23,612
Total operating expenses	235,846			223,593			680,612			651,342
Operating income	87,914			80,675			116,620			126,522
Other Income and Deductions:
Interest income	3,770			4,523			12,052			14,538
Gains (losses) on investments held by NDT	(4,109		)	2,206			7,688			2,606
Other income	1,179			807			1,921			11,989
Other deductions	(2,643		)	(1,111		)	(5,480		)	(3,526		)
Net other income (deductions)	(1,803		)	6,425			16,181			25,607
Interest Charges	18,487			18,011			54,593			54,473
Earnings before Income Taxes	67,624			69,089			78,208			97,656
Income Taxes	25,052			25,926			26,574			34,748
Net Earnings	42,572			43,163			51,634			62,908
(Earnings) Attributable to Valencia Non-controlling Interest	(4,111		)	(3,909		)	(10,764		)	(10,305		)
Net Earnings Attributable to PNM	38,461			39,254			40,870			52,603
Preferred Stock Dividends Requirements	(132		)	(132		)	(396		)	(396		)
Net Earnings Available for PNM Common Stock	$	38,329		$	39,122		$	40,474		$	52,207

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 BALANCE SHEETS

(Unaudited)

	September 30, 2011		December 31, 2010
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	5,034	$	10,336
Accounts receivable, net of allowance for uncollectible accounts of $1,645 and $1,483	80,154		58,785
Unbilled revenues	41,417		39,053
Other receivables	45,724		56,951
Affiliate receivables	8,893		8,605
Materials, supplies, and fuel stock	50,429		49,454
Regulatory assets	27,630		35,835
Commodity derivative instruments	3,716		1,443
Income taxes receivable	82,662		76,941
Other current assets	41,653		46,635
Total current assets	387,312		384,038
Other Property and Investments:
Investment in PVNGS lessor notes	79,390		103,871
Investments held by NDT	157,001		156,922
Other investments	4,193		5,068
Non-utility property	976		976
Total other property and investments	241,560		266,837
Utility Plant:
Plant in service and plant held for future use	3,930,362		3,818,722
Less accumulated depreciation and amortization	1,294,723		1,259,957
	2,635,639		2,558,765
Construction work in progress	124,607		115,628
Nuclear fuel, net of accumulated amortization of $36,722 and $26,247	78,218		72,901
Net utility plant	2,838,464		2,747,294
Deferred Charges and Other Assets:
Regulatory assets	341,089		357,944
Goodwill	51,632		51,632
Commodity derivative instruments	247		—
Other deferred charges	76,164		67,828
Total deferred charges and other assets	469,132		477,404
	$	3,936,468	$	3,875,573

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 BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	257,000		$	190,000
Accounts payable	48,077			51,931
Affiliate payables	17,788			8,528
Accrued interest and taxes	49,680			25,773
Regulatory liabilities	429			724
Commodity derivative instruments	1,746			3,110
Dividends declared	132			39,254
Current portion of accumulated deferred income taxes	9,783			9,783
Other current liabilities	53,943			65,858
Total current liabilities	438,578			394,961
Long-term Debt	1,055,760			1,055,748
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	463,918			446,657
Accumulated deferred investment tax credits	16,350			18,089
Regulatory liabilities	320,518			299,763
Asset retirement obligations	76,499			75,888
Accrued pension liability and postretirement benefit cost	213,607			253,948
Commodity derivative instruments	1,913			2,009
Other deferred credits	103,396			108,455
Total deferred credits and liabilities	1,196,201			1,204,809
Total liabilities	2,690,539			2,655,518
Commitments and Contingencies (See Note 9)
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)	1,018,776			1,018,776
Accumulated other comprehensive income (loss), net of income taxes	(71,966		)	(66,786		)
Retained earnings	203,621			171,359
Total PNM common stockholder’s equity	1,150,431			1,123,349
Non-controlling interest in Valencia	83,969			85,177
Total equity	1,234,400			1,208,526
	$	3,936,468		$	3,875,573

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,
	2011			2010
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	51,634		$	62,908
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	97,918			85,289
PVNGS firm-sales contract revenue	(2,558		)	(43,535		)
Deferred income tax expense	33,835			33,934
Net unrealized (gains) losses on derivatives	(4,120		)	7,157
Realized (gains) losses on investments held by NDT	(7,688		)	(2,606		)
Regulatory disallowances	17,479			—
Other, net	5,786			6,529
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(25,871		)	(8,938		)
Materials, supplies, and fuel stock	(974		)	(1,949		)
Other current assets	1,626			(21,861		)
Other assets	8,187			6,431
Accounts payable	(2,013		)	(406		)
Accrued interest and taxes	18,186			53,266
Other current liabilities	(4,173		)	(51,652		)
Other liabilities	(45,417		)	(29,614		)
Net cash flows from operating activities	141,837			94,953
Cash Flows From Investing Activities:
Utility plant additions	(185,402		)	(150,087		)
Proceeds from sales of NDT investments	121,202			57,098
Purchases of NDT investments	(122,174		)	(59,395		)
Return of principal on PVNGS lessor notes	32,274			29,851
Other, net	496			1,165
Net cash flows from investing activities	(153,604		)	(121,368		)

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

17

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	67,000			55,000
Long-term borrowings	—			403,845
Repayment of long-term debt	—			(403,845		)
Payments received on PVNGS firm-sales contracts	2,558			22,872
Equity transactions with Valencia’s owner	(11,972		)	(11,149		)
Proceeds from transmission interconnection arrangements	1,246			—
Repayment of transmission interconnection arrangements	(4,637		)	—
Dividends paid	(47,730		)	(28,392		)
Debt issuance costs and other	—			(4,298		)
Net cash flows from financing activities	6,465			34,033
Change in Cash and Cash Equivalents	(5,302		)	7,618
Cash and Cash Equivalents at Beginning of Period	10,336			1,373
Cash and Cash Equivalents at End of Period	$	5,034		$	8,991
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	40,582		$	43,298
Income taxes paid (refunded), net	$	(1,539	)	$	(35,189	)

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 STATEMENTS 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, 2010	$	1,018,776	$	(66,786	)	$	171,359		$	1,123,349		$	85,177		$	1,208,526
Valencia’s transactions with its owner	—		—			—			—			(11,972		)	(11,972		)
Net earnings	—		—			40,870			40,870			10,764			51,634
Total other comprehensive income (loss)	—		(5,180		)	—			(5,180		)	—			(5,180		)
Dividends declared on preferred stock	—		—			(396		)	(396		)	—			(396		)
Dividends declared on common stock	—		—			(8,212		)	(8,212		)	—			(8,212		)
Balance at September 30, 2011	$	1,018,776	$	(71,966	)	$	203,621		$	1,150,431		$	83,969		$	1,234,400

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 STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
				(In thousands)
Net Earnings	$	42,572		$	43,163		$	51,634		$	62,908
Other Comprehensive Income (Loss):
Unrealized Gain on Investment Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit of $1,123, $(4,270), $(8,157), and $(4,212)	(1,713		)	6,516			12,448			6,428
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,593, $1,145, $11,555, and $2,475	(2,431		)	(1,747		)	(17,632		)	(3,776		)
Pension liability adjustment, net of income tax (expense) benefit of $(423), $0, $9 and $147	646			—			(13		)	(223		)
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $(674), $0, and $(3,441)	—			1,029			—			5,252
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $0, $3,525, $(11), and $8,735	—			(5,379		)	17			(13,329		)
Total Other Comprehensive Income (Loss)	(3,498		)	419			(5,180		)	(5,648		)
Comprehensive Income	39,074			43,582			46,454			57,260
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,111		)	(3,909		)	(10,764		)	(10,305		)
Comprehensive Income Attributable to PNM	$	34,963		$	39,673		$	35,690		$	46,955

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,
	2011			2010				2011				2010
				(In thousands)
Electric Operating Revenues:
Non-affiliates	$	54,787		$	49,709			$	150,175			$	131,233
Affiliate	12,196			11,495				30,608				30,717
Total electric operating revenues	66,983			61,204				180,783				161,950
Operating Expenses:
Cost of energy	10,307			9,276				30,719				27,383
Administrative and general	9,998			9,620				29,798				27,932
Regulatory disallowances	—			—				3,923				—
Depreciation and amortization	12,674			11,594				33,662				31,728
Transmission and distribution costs	6,072			5,192				17,597				15,121
Taxes other than income taxes	6,381			5,899				16,113				15,481
Total operating expenses	45,432			41,581				131,812				117,645
Operating income	21,551			19,623				48,971				44,305
Other Income and Deductions:
Interest income	1			—			1	1			1	1
Other income	418			96				1,068				769
Other deductions	(105		)	(8		)		(181		)		(52		)
Net other income (deductions)	314			88				888				718
Interest Charges	7,276			7,661				21,880				23,483
Earnings Before Income Taxes	14,589			12,050				27,979				21,540
Income Taxes	5,721			4,721				10,845				8,461
Net Earnings	$	8,868		$	7,329			$	17,134			$	13,079

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 BALANCE SHEETS

(Unaudited)

	September 30, 2011		December 31, 2010
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	9,000	$	1
Accounts receivable	20,851		12,742
Unbilled revenues	6,376		5,734
Other receivables	696		1,677
Affiliate receivables	5,962		3,956
Materials and supplies	2,663		2,787
Regulatory assets	1,063		457
Current portion of accumulated deferred income taxes	1,876		1,876
Other current assets	896		618
Total current assets	49,383		29,848
Other Property and Investments:
Other investments	267		282
Non-utility property	2,240		2,244
Total other property and investments	2,507		2,526
Utility Plant:
Plant in service and plant held for future use	910,202		885,325
Less accumulated depreciation and amortization	318,863		302,333
	591,339		582,992
Construction work in progress	30,062		12,375
Net utility plant	621,401		595,367
Deferred Charges and Other Assets:
Regulatory assets	134,848		144,522
Goodwill	226,665		226,665
Other deferred charges	6,809		12,029
Total deferred charges and other assets	368,322		383,216
	$	1,041,613	$	1,010,957

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 BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt – affiliate	$	—		$	1,200
Accounts payable	11,831			5,537
Affiliate payables	2,506			1,015
Accrued interest and taxes	27,463			23,185
Other current liabilities	3,133			3,292
Total current liabilities	44,933			34,229
Long-term Debt	310,807			310,337
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	152,608			142,121
Regulatory liabilities	42,569			42,702
Asset retirement obligations	684			648
Accrued pension liability and postretirement benefit cost	13,794			16,224
Other deferred credits	11,961			11,413
Total deferred credits and other liabilities	221,616			213,108
Total liabilities	577,356			557,674
Commitments and Contingencies (See Note 9)
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	423,042			430,108
Accumulated other comprehensive income (loss), net of income taxes	(579		)	(1,485		)
Retained earnings	41,730			24,596
Total common stockholder’s equity	464,257			453,283
	$	1,041,613		$	1,010,957

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 STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	17,134		$	13,079
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	36,352			34,748
Deferred income tax expense (benefit)	9,981			(6,015		)
Regulatory disallowances	3,923			—
Other, net	(69		)	(939		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(8,751		)	(3,660		)
Materials and supplies	124			(641		)
Other current assets	(1,547		)	(1,037		)
Other assets	(2,985		)	(3,147		)
Accounts payable	1,858			(1,253		)
Accrued interest and taxes	4,277			18,034
Other current liabilities	2,383			252
Other liabilities	(1,101		)	(478		)
Net cash flows from operating activities	61,579			48,943
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(44,214		)	(23,311		)
Net cash flows from investing activities	(44,214		)	(23,311		)

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 STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net – affiliate	(1,200		)	(19,800		)
Long-term borrowings	50,000			—
Repayment of long-term debt	(50,000		)	—
Dividends paid	(7,066		)	(5,750		)
Debt issuance costs and other	(100		)	(124		)
Net cash flows from financing activities	(8,366		)	(25,674		)
Change in Cash and Cash Equivalents	8,999			(42		)
Cash and Cash Equivalents at Beginning of Period	1			138
Cash and Cash Equivalents at End of Period	$	9,000		$	96
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	14,474		$	14,719
Income taxes paid (refunded), net	$	3,250		$	2,940

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 STATEMENTS 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, 2010	$	64	$	430,108		$	(1,485	)	$	24,596	$	453,283
Net earnings	—		—			—			17,134		17,134
Total other comprehensive income	—		—			906			—		906
Dividends declared on common stock	—		(7,066		)	—			—		(7,066		)
Balance at September 30, 2011	$	64	$	423,042		$	(579	)	$	41,730	$	464,257

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

26

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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In thousands)
Net Earnings	$	8,868		$	7,329		$	17,134		$	13,079
Other Comprehensive Income (Loss):
Pension liability adjustment, net of income tax (expense)    benefit of $(1), $0, $169, and $0	2			—			(305		)	—
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $110, $416, $382, and $1,307	(198		)	(750		)	(689		)	(2,357		)
Reclassification adjustment for losses included in net earnings, net of income tax (benefit) of $(850), $(92), $(1,052), and $(297)	1,535			166			1,900			537
Total Other Comprehensive Income (Loss)	1,339			(584		)	906			(1,820		)
Comprehensive Income	$	10,207		$	6,745		$	18,040		$	11,259

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

27

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO 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, 2011 and December 31, 2010, and the consolidated results of operations and comprehensive income for the three months and nine months ended September 30, 2011 and 2010, and cash flows for the nine months ended September 30, 2011 and 2010. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated.

The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. The term “Company” is used when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are indicated as such. Certain amounts in the 2010 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2011 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited, and 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 2010 Annual Reports on Form 10-K. 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.

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. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. PNMR entered into an agreement to sell First Choice on September 23, 2011 and the sale was completed on November 1, 2011. See Note 16. In addition, PNM consolidates the PVNGS Capital Trust and Valencia. PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are allocated to the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include transmission and distribution services; lease, interest, and income tax sharing payments; and dividends paid on common stock. Intercompany transactions and balances have been eliminated, as appropriate. 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 $0.125 per share in July 2011 and July 2010, 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 $0.125 per share in September 2011 and September 2010, which are reflected as being in the third quarter within "Dividends Declared per Common Share."

28

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM declared cash dividends on its common stock to PNMR of $39.1 million in December 2010 that was paid in January 2011, $4.6 million in March 2011 that was paid in April 2011, and $3.6 million in June 2011 that was paid in July 2011. PNM declared and paid cash dividends to PNMR of $28.0 million in the nine months ended September 30, 2010. TNMP declared and paid cash dividends to PNMR of $7.1 million and $5.8 million in the nine months ended September 30, 2011 and 2010. TNMP dividends were recorded as reductions of its paid-in-capital.

(2) 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.

On April 18, 2007, PNM entered into a PPA to purchase all of the electric capacity and energy from Valencia, a natural gas-fired power plant near Belen, New Mexico. Valencia became operational on May 30, 2008. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. The total construction cost for the facility was $90.0 million. The term of the PPA is for 20 years beginning June 1, 2008, with the full output of the plant estimated to be 145 MW. During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or of the entity that owns the plant. PNM estimates that the plant will typically operate during peak periods of energy demand in summer. PNM is obligated to pay fixed O&M and capacity charges in addition to variable O&M charges under this PPA. For the three months and nine months ended September 30, 2011, PNM paid $4.6 million and $13.7 million for fixed charges and $0.9 million and $1.3 million for variable charges. For the three months and nine months ended September 30, 2010, PNM paid $4.6 million and $13.5 million for fixed charges and $0.8 million and $1.0 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 evaluated the accounting treatment of this arrangement and 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 since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. The significant factors considered in reaching that conclusion are that PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. As the primary beneficiary, PNM has consolidated the entity in its financial statements beginning on the commercial operations date. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the consolidated financial statements of PNM although PNM has no legal ownership interest or voting control of the variable interest entity. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
				(In thousands)
Operating revenues	$	5,505		$	5,275		$	15,024		$	14,502
Operating expenses	(1,394		)	(1,366		)	(4,260		)	(4,197		)
Earnings attributable to non-controlling interest	$	4,111		$	3,909		$	10,764		$	10,305

29

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Financial Position

	September 30,		December 31,
	2011		2010
	(In thousands)
Current assets	$	3,588	$	2,372
Net property, plant and equipment	81,493		83,617
Total assets	85,081		85,989
Current liabilities	1,112		812
Owners’ equity – non-controlling interest	$	83,969	$	85,177

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. There are currently eight separate lease agreements with eight different trusts whose beneficial owners are five different institutional investors. PNM is not the legal or tax owner of the leased assets. The beneficial owners of the trusts possess all of the voting control and pecuniary interests in the trusts. 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. PNM has options to renew the leases at fixed rates set forth in the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities. 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 $105.1 million as of September 30, 2011 over the remaining 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, 2011, PNM could have been required to pay the beneficial owners up to approximately $178.3 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 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, 2011 and $26.0 million at December 31, 2010 and 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 2010 Annual Reports on Form 10-K.

PNM has evaluated the PVNGS lease arrangements 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. The significant factors considered in reaching this conclusion are: the periods covered by fixed price renewal options are significantly shorter than the anticipated remaining useful lives of the assets, particularly since on April 21, 2011 the NRC approved an extension in the operating licenses for the plants for 20 years through 2045 for Unit 1 and 2046 for Unit 2 (see Note 13); PNM’s only financial obligation to the trusts is to make the fixed lease payments and the payments do not vary based on the output of the plants or their performance; during the lease term, the economic performance of the trusts is substantially fixed due to the fixed lease payments; PNM is only one of several participants in PVNGS and is not the operating agent for the plants, so PNM does not significantly influence the day to day operations of the plants; furthermore, the operations of the plants, including plans for their decommissioning, are highly regulated by the NRC, leaving little room for the participants to operate the plants in a manner that impacts the economic performance of the trusts; the economic performance of the trusts at the end of the lease terms is dependent upon the fair value and remaining lives of the plants at that time, which are determined by factors such as power prices, outlook for nuclear power, and the impacts of potential carbon legislation or regulation, all which are outside of PNM’s control; and while PNM has some potential benefit from its renewal options, the vast majority of the value at the end of the leases will accrue to the beneficial owners of the trusts, particularly given increases in the value of existing nuclear generating facilities, which emit no GHG, resulting from anticipated carbon legislation or regulation.

PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. This arrangement was entered

30

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

into prior to December 31, 2003 and PNM has been 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 is unable to make those determinations and, as provided in GAAP, continues to account for this PPA as an operating lease. PNM makes fixed and variable payments to Delta under the PPA. 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. For the three months and nine months ended September 30, 2011, PNM incurred fixed payments of $1.5 million and $4.5 million and variable payments of $0.7 million and $1.0 million under the PPA. For the three months and nine months ended September 30, 2010, PNM incurred fixed payments of $1.5 million and $4.5 million and variable payments of $0.2 million and $0.4 million under the PPA. PNM’s only quantifiable obligation under the PPA is to make the fixed payments, which as of September 30, 2011, aggregated $52.6 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. PNM has no other obligations or commitments with respect to Delta.

(3) Segment Information

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

PNM Electric

PNM Electric includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM Electric provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico, generation services to firm requirements customers in New Mexico and Arizona, and the sale of transmission to third parties. PNM Electric also includes the generation and sale of electricity into the wholesale market. This includes the asset optimization of PNM’s jurisdictional assets as well as the capacity of PVNGS Unit 3, which is excluded from retail rates. FERC has jurisdiction over wholesale power and transmission rates.

TNMP Electric

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

First Choice

First Choice is a certified retail electric provider operating in Texas, which allows it to provide electricity to residential, small commercial, and governmental customers. Although First Choice is regulated in certain respects by the PUCT, it is not subject to traditional rate regulation. PNMR entered into an agreement to sell First Choice on September 23, 2011 and the sale was completed on November 1, 2011. See Note 16.

Optim Energy

PNMR owned 50% of Optim Energy until September 23, 2011, when PNMR's ownership interest was reduced to 1%. Optim Energy was considered a separate segment for PNMR, which was held in the Corporate and Other segment. PNMR accounted for its investment in Optim Energy using the equity method of accounting until September 23, 2011 and is using the cost method thereafter. Optim Energy’s revenues and expenses are not included in PNMR’s consolidated revenues and expenses or the following tables. PNMR fully impaired its investment in Optim Energy as of December 31, 2010. See Note 11.

Corporate and Other

PNMR Services Company is included in the Corporate and Other segment.

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

31

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNMR SEGMENT INFORMATION

	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended September 30, 2011	(In thousands)
Operating revenues	$	323,760		$	54,787		$	170,999		$	(48	)	$	549,498
Intersegment revenues	—			12,196			—			(12,196		)	—
Total revenues	323,760			66,983			170,999			(12,244		)	549,498
Cost of energy	108,708			10,307			144,035			(12,196		)	250,854
Gross margin	215,052			56,676			26,964			(48		)	298,644
Other operating expenses	102,080			22,451			25,076			(1,617		)	147,990
Depreciation and amortization	25,058			12,674			346			4,292			42,370
Operating income (loss)	87,914			21,551			1,542			(2,723		)	108,284
Interest income	3,770			1			29			(52		)	3,748
Other income (deductions)	(5,573		)	313			(115		)	(1,664		)	(7,039		)
Net interest charges	(18,487		)	(7,276		)	(249		)	(5,112		)	(31,124		)
Segment earnings (loss) before income taxes	67,624			14,589			1,207			(9,551		)	73,869
Income taxes (benefit)	25,052			5,721			594			(5,403		)	25,964
Segment earnings (loss)	42,572			8,868			613			(4,148		)	47,905
Valencia non-controlling interest	(4,111		)	—			—			—			(4,111		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	38,329		$	8,868		$	613		$	(4,148	)	$	43,662
Nine Months Ended September 30, 2011
Operating revenues	$	797,232		$	150,175		$	405,485		$	(145	)	$	1,352,747
Intersegment revenues	—			30,608			—			(30,608		)	—
Total revenues	797,232			180,783			405,485			(30,753		)	1,352,747
Cost of energy	279,419			30,719			303,285			(30,609		)	582,814
Gross margin	517,813			150,064			102,200			(144		)	769,933
Other operating expenses	329,502			67,431			67,693			(7,172		)	457,454
Depreciation and amortization	71,691			33,662			987			12,775			119,115
Operating income (loss)	116,620			48,971			33,520			(5,747		)	193,364
Interest income	12,052			1			63			(106		)	12,010
Other income (deductions)	4,129			887			(494		)	(4,913		)	(391		)
Net interest charges	(54,593		)	(21,880		)	(535		)	(15,243		)	(92,251		)
Segment earnings (loss) before income taxes	78,208			27,979			32,554			(26,009		)	112,732
Income taxes (benefit)	26,574			10,845			11,833			(12,046		)	37,206
Segment earnings (loss)	51,634			17,134			20,721			(13,963		)	75,526
Valencia non-controlling interest	(10,764		)	—			—			—			(10,764		)
Subsidiary preferred stock dividends	(396		)	—			—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	40,474		$	17,134		$	20,721		$	(13,963	)	$	64,366
At September 30, 2011:
Total Assets	$	3,936,468		$	1,041,613		$	274,741		$	119,818		$	5,372,640
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310
Additions to utility and non-utility plant included in accounts payable	$	6,811		$	4,672		$	106		$	253		$	11,842

32

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended September 30, 2010	(In thousands)
Operating revenues	$	304,268		$	49,709		$	149,729		$	(53	)	$	503,653
Intersegment revenues	—			11,495			—			(11,495		)	—
Total revenues	304,268			61,204			149,729			(11,548		)	503,653
Cost of energy	98,030			9,276			119,358			(11,495		)	215,169
Gross margin	206,238			51,928			30,371			(53		)	288,484
Other operating expenses	102,452			20,711			23,952			(3,019		)	144,096
Depreciation and amortization	23,111			11,594			210			4,065			38,980
Operating income (loss)	80,675			19,623			6,209			(1,099		)	105,408
Interest income	4,523			—			3			(27		)	4,499
Equity in net earnings (loss) of Optim Energy	—			—			—			2,495			2,495
Other income (deductions)	1,902			88			(66		)	(1,603		)	321
Net interest charges	(18,011		)	(7,661		)	(364		)	(5,281		)	(31,317		)
Segment earnings (loss) before income taxes	69,089			12,050			5,782			(5,515		)	81,406
Income taxes (benefit)	25,926			4,721			2,225			(4,059		)	28,813
Segment earnings (loss)	43,163			7,329			3,557			(1,456		)	52,593
Valencia non-controlling interest	(3,909		)	—			—			—			(3,909		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	39,122		$	7,329		$	3,557		$	(1,456	)	$	48,552
Nine Months Ended September 30, 2010
Operating revenues	$	777,864		$	131,233		$	384,034		$	(266	)	$	1,292,865
Intersegment revenues	—			30,717			—			(30,717		)	—
Total revenues	777,864			161,950			384,034			(30,983		)	1,292,865
Cost of energy	264,102			27,383			296,469			(30,716		)	557,238
Gross margin	513,762			134,567			87,565			(267		)	735,627
Other operating expenses	318,353			58,534			65,652			(10,109		)	432,430
Depreciation and amortization	68,887			31,728			683			12,336			113,634
Operating income (loss)	126,522			44,305			21,230			(2,494		)	189,563
Interest income	14,538			1			16			53			14,608
Equity in net earnings (loss) of Optim Energy	—			—			—			(5,714		)	(5,714		)
Other income (deductions)	11,069			717			(164		)	(4,544		)	7,078
Net interest charges	(54,473		)	(23,483		)	(1,062		)	(15,470		)	(94,488		)
Segment earnings (loss) before income taxes	97,656			21,540			20,020			(28,169		)	111,047
Income taxes (benefit)	34,748			8,461			7,363			(13,207		)	37,365
Segment earnings (loss)	62,908			13,079			12,657			(14,962		)	73,682
Valencia non-controlling interest	(10,305		)	—			—			—			(10,305		)
Subsidiary preferred stock dividends	(396		)	—			—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	52,207		$	13,079		$	12,657		$	(14,962	)	$	62,981
At September 30, 2010:
Total Assets	$	3,812,829		$	1,004,785		$	259,621		$	303,574		$	5,380,809
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310

33

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(4) Fair Value of Derivative and Other Financial Instruments

Energy Related Derivative Contracts

Overview

The Company is exposed to certain risks relating to its ongoing business operations. 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 or fuel used to generate electricity, or to manage anticipated generation capacity in excess of forecasted demand from existing customers. Substantially all of the Company’s energy related derivative contracts manage commodity risk and the Company does not currently engage in speculative trading.

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. The Company 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. The Company monitors the market risk of its commodity contracts using VaR and GEaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.

PNM is required to meet the demand and energy needs of its retail and firm requirements customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm requirements 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. 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.

First Choice was responsible for energy supply related to the sale of electricity to retail customers in Texas. TECA contains no provisions for the specific recovery of fuel and purchased power costs. The rates charged to First Choice customers were negotiated with each customer. First Choice purchased wholesale power in the competitive ERCOT wholesale market and sold power to retail customers in the competitive ERCOT retail market. Many of these retail customers bought power from First Choice for a contracted period of time at a fixed price so First Choice was exposed to price risk if the wholesale power price changed during the time of the contract. First Choice’s strategy was to minimize its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins. However, if actual fixed price retail loads varied significantly from forecasts (for example, due to extreme weather, other significant load changes or contract breaches), First Choice had a residual exposure to wholesale power price risk for the mismatch between the forecast and actual load.

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 settle.

For derivative transactions meeting the definition of a cash flow hedge, the Company documents the relationships between the hedging instruments and the items being hedged. This documentation includes the strategy that supports executing the specific transaction and the methods utilized to assess the effectiveness of the hedges. Changes in the fair value of contracts qualifying for cash flow hedge accounting are included in AOCI to the extent effective. Ineffectiveness gains and losses were immaterial for all periods presented. Gains or losses related to cash flow hedge instruments, including those de-designated, are reclassified from AOCI when the hedged transaction settles and impacts earnings. Based on market prices at September 30, 2011, after-tax

34

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

losses of $0.1 million for PNMR and zero for PNM would be reclassified from AOCI into earnings during the next twelve months. However, the actual amount reclassified into earnings may vary due to changes in the timing or nature of the underlying transactions. As of September 30, 2011 and December 31, 2010, the Company is 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 either economic hedges or trading transactions. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. Trading transactions included speculative transactions, which the Company ceased in 2008, and transactions that lock in margin with no forward market risk and are not economic hedges. Changes in the fair value of these transactions are reflected on a net basis in operating revenues.

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 own 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.

The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements. At September 30, 2011 and December 31, 2010, amounts recognized for the legal right to reclaim cash collateral were $0.3 million and $3.4 million for PNMR and zero and $3.0 million for PNM. In addition, at September 30, 2011 and December 31, 2010, amounts posted as cash collateral under margin arrangements were $28.9 million and $32.0 million for PNMR and $0.1 million and $2.1 million for PNM. Cash collateral amounts are included in other current assets on the Condensed Consolidated Balance Sheets. PNMR and PNM had no obligations to return cash collateral at September 30, 2011 and December 31, 2010.

Commodity Derivatives

Commodity derivative instruments are summarized as follows:

	PNMR						PNM
	Economic Hedges						Economic Hedges
	September 30, 2011			December 31, 2010			September 30, 2011			December 31, 2010
	(In thousands)
Current assets	$	32,168		$	15,999		$	3,716		$	1,443
Deferred charges	9,064			5,264			247			—
	41,232			21,263			3,963			1,443
Current liabilities	(41,018		)	(31,407		)	(1,746		)	(3,110		)
Long-term liabilities	(16,373		)	(12,831		)	(1,913		)	(2,009		)
	(57,391		)	(44,238		)	(3,659		)	(5,119		)
Net	$	(16,159	)	$	(22,975	)	$	304		$	(3,676	)

The Company had no trading or designated cash flow hedge transactions at September 30, 2011 and December 31, 2010. On April 20, 2010, PNM received NMPRC approval of a hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.8 million of current assets, less than $0.1 million of deferred charges, $0.4 million in current liabilities, and less than $0.1 million of long-term liabilities at September 30, 2011, and $0.6

35

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

million of current assets at December 31, 2010 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.

The following table presents the effect of commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.

	Economic Hedges						Trading Transactions					Qualified Cash Flow Hedges
	September 30,						September 30,					September 30,
	2011			2010			2011		2010			2011			2010
Three Months Ended	(In thousands)
PNMR
Electric operating revenues	$	2,915		$	(2,131	)	$	—	$	30		$	—		$	9,006
Cost of energy	(2,873		)	(20,222		)	—		—			66			(684		)
Total gain (loss)	$	42		$	(22,353	)	$	—	$	30		$	66		$	8,322
Recognized in OCI												$	(66	)	$	(6,531	)
PNM
Electric operating revenues	$	2,915		$	(2,131	)	$	—	$	—		$	—		$	9,006
Cost of energy	(562		)	(1,781		)	—		—			—			(35		)
Total gain (loss)	$	2,353		$	(3,912	)	$	—	$	—		$	—		$	8,971
Recognized in OCI												$	—		$	(7,181	)
Nine Months Ended
PNMR
Electric operating revenues	$	4,250		$	(4,138	)	$	—	$	(3	)	$	—		$	22,294
Cost of energy	(2,788		)	(49,451		)	—		—			(183		)	(1,930		)
Total gain (loss)	$	1,462		$	(53,589	)	$	—	$	(3	)	$	(183	)	$	20,364
Recognized in OCI												$	183		$	(11,349	)
PNM
Electric operating revenues	$	4,250		$	(4,138	)	$	—	$	—		$	—		$	22,294
Cost of energy	(404		)	(5,443		)	—		—			—			(21		)
Total gain (loss)	$	3,846		$	(9,581	)	$	—	$	—		$	—		$	22,273
Recognized in OCI												$	—		$	(13,259	)

Commodity contract volume positions are presented in Decatherms 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
	Decatherms	MWh
September 30, 2011
PNMR	27,187,500	3,597,170
PNM	1,425,000	(961,192	)
December 31, 2010
PNMR	22,767,500	1,693,431
PNM	1,882,500	(990,120	)

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

36

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

collateral from the Company if the Company’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide such counterparty 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, 2011
PNMR	$	12,787	$	—	$	4,026
PNM	$	3,486	$	—	$	3,064
December 31, 2010
PNMR	$	8,113	$	—	$	2,642
PNM	$	291	$	—	$	119

Sale of Power from PVNGS Unit 3

In April 2008, PNM entered into three separate contracts for the sale of capacity and energy related to its entire ownership interest in PVNGS Unit 3, which is 135 MW.  Under two of the contracts, PNM sold 90 MW of firm capacity and energy.  Under the third contract, PNM sold 45 MW of unit contingent capacity and energy. The term of the contracts was May 1, 2008 through December 31, 2010.  Under the two firm contracts, the two buyers made prepayments of $40.6 million and $30.0 million.  These amounts were recorded as deferred revenue and were amortized over the life of the contracts. The prepayments received under the firm contracts, as well as required subsequent monthly payments on them, are shown as a financing activity in the Condensed Consolidated Statements of Cash Flows as required by GAAP. The firm contracts were accounted for as cash flow hedges and changes in fair value were included in AOCI. The contingent contract was accounted for as a normal sale. Beginning January 1, 2011, PNM is selling its 135 MW interest in PVNGS Unit 3 daily at market prices. PNM has established fixed rates for the majority of these sales through the end of 2011 through financial hedging arrangements that are accounted for as economic hedges.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS. The NDT holds equity and fixed income securities. PNMR and PNM do not have any unrealized losses on available-for-sale securities. The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table.

37

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	September 30, 2011				December 31, 2010
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Equity securities:
Domestic value	$	1,137	$	22,051	$	5,108	$	25,491
Domestic growth	12,356		47,358		17,239		48,237
Multinational	243		12,509		2,730		10,670
Fixed income securities:
Municipals	2,486		39,316		837		37,595
U.S. Government	1,305		22,779		348		21,541
Corporate and other	728		9,292		573		8,402
Cash and equivalents	—		3,696		—		4,986
	$	18,255	$	157,001	$	26,835	$	156,922

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,
	2011			2010			2011			2010
				(In thousands)
Proceeds from sales	$	26,312		$	20,813		$	121,202		$	57,098
Gross realized gains	$	2,800		$	1,568		$	16,290		$	4,999
Gross realized (losses)	$	(1,847	)	$	(1,227	)	$	(4,129	)	$	(3,099	)

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, including the EIP lessor note.

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

At September 30, 2011, 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	$	683	$	—	$	—
After 1 year through 5 years	20,259		123,206		112,083
After 5 years through 10 years	10,740		3,370		—
Over 10 years	39,705		—		—
	$	71,387	$	126,576	$	112,083

38

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The carrying amount and fair value of held-to-maturity debt securities and other non-derivative financial instruments (including current maturities) are:

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
PNMR
Long-term debt	$	1,566,329	$	1,751,691	$	1,565,847	$	1,659,674
Investment in PVNGS lessor notes	$	107,435	$	108,345	$	136,145	$	141,663
Other investments	$	14,639	$	21,070	$	18,791	$	21,675
PNM
Long-term debt	$	1,055,760	$	1,107,490	$	1,055,748	$	1,056,864
Investment in PVNGS lessor notes	$	107,435	$	108,345	$	136,145	$	141,663
Other investments	$	4,193	$	4,522	$	5,068	$	5,563
TNMP
Long-term debt	$	310,807	$	423,253	$	310,337	$	385,220
Other investments	$	267	$	267	$	282	$	282

The fair value of long-term debt shown above was primarily determined using quoted market values, as were certain items included in other investments. To the extent market values were not available, fair value was determined by discounting the cash flows for the instrument using quoted interest rates for comparable instruments.

Other 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 has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models.

For NDT 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. Fair values of Level 3 commodity derivatives are determined in a manner similar to those in Level 2, but are at a lower level in the hierarchy due to low transaction volume or market illiquidity that significantly limits the availability of observable market data.

39

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Derivatives and Investments

The fair values of derivatives and investments that are recorded at fair value on the Condensed Consolidated Balance Sheets are as follows:

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
September 30, 2011				(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	3,696		$	3,696		$	—		$	—
Equity securities:
Domestic value	22,051			22,051			—			—
Domestic growth	47,358			47,358			—			—
Multinational	12,509			12,509			—			—
Fixed income securities:
U.S. government	22,779			18,149			4,630			—
Municipals	39,316			—			39,316			—
Corporate and other	9,292			—			9,292			—
Total NDT investments	$	157,001		$	103,763		$	53,238		$	—
PNMR
Commodity derivative assets	$	41,232		$	19,589		$	18,982		$	1,302
Commodity derivative liabilities	(57,391		)	(41,574		)	(14,094		)	(364		)
Net	$	(16,159	)	$	(21,985	)	$	4,888		$	938
PNM
Commodity derivative assets	$	3,963		$	—		$	3,963		$	—
Commodity derivative liabilities	(3,659		)	—			(3,659		)	—
Net	$	304		$	—		$	304		$	—

40

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
December 31, 2010	(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	4,986		$	4,986		$	—		$	—
Equity securities:
Domestic value	25,491			25,491			—			—
Domestic growth	48,237			48,237			—			—
Multinational	10,670			10,670			—			—
Fixed income securities:
U.S. government	21,541			16,613			4,928			—
Municipals	37,595			—			37,595			—
Corporate and other	8,402			—			8,402			—
Total NDT investments	$	156,922		$	105,997		$	50,925		$	—
PNMR
Commodity derivative assets	$	21,263		$	8,646		$	12,308		$	272
Commodity derivative liabilities	(44,238		)	(26,378		)	(16,729		)	(1,094		)
Net	$	(22,975	)	$	(17,732	)	$	(4,421	)	$	(822	)
PNM
Commodity derivative assets	$	1,443		$	—		$	1,443		$	—
Commodity derivative liabilities	(5,119		)	—			(5,119		)	—
Net	$	(3,676	)	$	—		$	(3,676	)	$	—

(1) The Level 1, 2 and 3 columns in the above table are presented based on the nature of each instrument. The total column is presented based on the balance sheet classification of the instruments and reflect unit of account reclassifications between commodity derivative assets and commodity derivative liabilities of $1.4 million for PNMR and zero for PNM at September 30, 2011 and less than $0.1 million for PNMR and zero for PNM at December 31, 2010. There were no transfers between levels for the three months and nine months ended September 30, 2011 and 2010.

41

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

	PNMR						PNM
	September 30,						September 30,
	2011			2010			2011		2010
Three Months Ended	(In thousands)
Balance at beginning of period	$	4,392		$	(278	)	$	—	$	—
Total gains (losses) included in earnings	(5,025		)	(945		)	—		—
Purchases	429			34			—		—
Settlements	1,142			(83		)	—		—
Balance at end of period	$	938		$	(1,272	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	589		$	(994	)	$	—	$	—
Nine Months Ended
Balance at beginning of period	$	(822	)	$	248		$	—	$	(17	)
Total gains (losses) included in earnings	201			(1,759		)	—		(128		)
Purchases	3,163			34			—		—
Settlements	(1,604		)	205			—		145
Balance at end of period	$	938		$	(1,272	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	1,455		$	(1,537	)	$	—	$	—

Gains and losses (realized and unrealized) for Level 3 fair value measurements included in earnings are reported in operating revenues and cost of energy as follows:

42

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	PNMR						PNM
	September 30,						September 30,
	2011			2010			2011		2010
Three Months Ended	(In thousands)
Gains (losses) included in earnings:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	(5,025		)	(945		)	—		—
Total	$	(5,025	)	$	(945	)	$	—	$	—
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	589			(994		)	—		—
Total	$	589		$	(994	)	$	—	$	—
Nine Months Ended
Gains (losses) included in earnings:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	201			(1,759		)	—		(128		)
Total	$	201		$	(1,759	)	$	—	$	(128	)
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	1,455			(1,537		)	—		—
Total	$	1,455		$	(1,537	)	$	—	$	—

(5) Earnings Per Share

In accordance with GAAP, dual presentation of basic and diluted earnings per share has been 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,
	2011		2010		2011		2010
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	43,662	$	48,552	$	64,366	$	62,981
Average Number of Common Shares:
Outstanding during period	86,673		86,673		86,673		86,673
Equivalents from convertible preferred stock (Note 7)	4,363		4,778		4,638		4,778
Vested awards of restricted stock	164		111		154		105
Average Shares - Basic	91,200		91,562		91,465		91,556
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	542		219		516		258
Average Shares - Diluted	91,742		91,781		91,981		91,814
Net Earnings Per Share of Common Stock:
Basic	$	0.48	$	0.53	$	0.70	$	0.69
Diluted	$	0.48	$	0.53	$	0.70	$	0.69

(1) Excludes the effect of out-of-the-money options for 1,923,608 shares of common stock at September 30, 2011.

43

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(6) Stock-Based Compensation

Information concerning stock-based compensation plans is contained in Note 13 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted in 2011 and awards of restricted stock have increased.

Stock Options

The following table summarizes activity in stock option plans for the nine months ended September 30, 2011:

	Shares		Weighted- Average Exercise Price		Aggregate Intrinsic Value			Weighted- Average Remaining Contract Life
Outstanding at beginning of period	3,948,262		$	18.33
Granted	—		$	—
Exercised	(254,394	)	$	10.99
Forfeited	(10,333	)	$	11.26
Expired	(102,338	)	$	24.96
Outstanding at end of period	3,581,197		$	18.68	$	8,950,188	(1)	5.12 years
Exercisable at end of period	3,045,556		$	21.97	$	6,011,541		4.60 years
Options available for future grant(2)	4,820,656

(1) At September 30, 2011, the exercise price of 1,923,608 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

(2) Includes shares available for grants of restricted stock.

The following table provides additional information concerning stock option activity:

	Nine Months Ended September 30,
Options for PNMR Common Stock	2011		2010
Weighted-average grant date fair value of options granted	$	—	$	3.05
Total fair value of options that vested (in thousands)	$	1,189	$	1,027
Total intrinsic value of options exercised (in thousands)	$	1,077	$	474

Restricted Stock and Performance Shares

The following table summarizes nonvested restricted stock activity for the nine months ended September 30, 2011:

Nonvested Restricted Stock	Shares		Weighted- Average Grant-Date Fair Value
Nonvested at beginning of period	237,021		$	9.24
Granted	308,985		$	13.10
Vested	(113,576	)	$	9.54
Forfeited	(1,000	)	$	13.67
Nonvested at end of period	431,430		$	11.92

44

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Compensation expense for restricted stock and performance stock awards was determined based on the market price of PNMR stock on the date of grant reduced by the present value of future dividends, which will not be received during the vesting period, applied to the total number of shares that were anticipated to fully vest.

The following table provides additional information concerning restricted stock:

	Nine Months Ended
	September 30,
Nonvested Restricted Stock	2011			2010
Weighted-average grant date fair value of shares granted	$	13.10		$	9.37
Total fair value of shares that vested (in thousands)	$	1,084		$	1,365
Expected quarterly dividends per share	$	0.125		$	0.125
Risk-free interest rate	1.20		%	1.36		%

Beginning in 2009, the Company issued performance share agreements to certain executives that are based upon the Company achieving specified performance targets over periods of one to three years. The determination of the number of shares ultimately issued depends on the levels at which the performance criteria are achieved and cannot be determined until after the performance periods end. For the targets based only on 2010 performance, near optimal level was attained resulting in 88,913 shares being awarded in 2011, which will vest evenly from 2012 through 2014 and are included in the number of shares granted in the above table. Excluded from the above table is a maximum of 560,461 shares based on performance targets through 2013 that would be issued and vest upon issuance if all performance criteria are achieved and all executives remain eligible.

(7) Capitalization

Information concerning financing activities is contained in Note 6 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

Short-term Debt

On October 31, 2011, PNMR entered into the PNMR Revolving Credit Facility, which has a financing capacity of $300.0 million, and PNM entered into the PNM Revolving Credit Facility, which has a financing capacity of $400.0 million. These new facilities expire on October 31, 2016, and include two one-year extension options, subject to approval by a majority of the lenders and, with respect to the PNM Revolving Credit Facility, regulatory approval. The new credit facilities replace the $517.0 million PNMR Facility and the $368.0 million PNM Facility, both of which would have expired in August 2012. The terms and conditions of the new facilities are substantially similar to the prior facilities. PNMR also has a local line of credit amounting to $5.0 million that expires in August 2012. TNMP has a revolving credit facility with financing capacity of $75.0 million under the TNMP Revolving Credit Facility that expires in December 2015. At September 30, 2011, the weighted average interest rate was 1.48% for the PNMR Facility and 0.88% for the PNM Facility. Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2011		2010
	(In thousands)
PNM – Revolving credit facility	$	257,000	$	190,000
TNMP – Revolving credit facility	—		—
PNMR
Revolving credit facility	32,000		32,000
Local lines of credit	—		—
	$	289,000	$	222,000

45

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On November 1, 2011, PNMR utilized a portion of the proceeds from the sale of First Choice (see Note 16) to repay short-term debt incurred to finance the October 5, 2011 payment for the purchase of PNMR's Series A preferred stock described below, as well as all other PNMR borrowings under the PNMR Revolving Credit Facility. In addition, on November 1, 2011, PNMR loaned $63.8 million to PNM under their intercompany loan agreement and PNM repaid all borrowings under the PNM Revolving Credit Facility. At November 1, 2011, PNMR, PNM, and TNMP had $235.4 million, $394.8 million, and $74.7 million of availability under their respective revolving credit facilities and local lines of credit, including reductions of availability due to outstanding letters of credit. Total availability at November 1, 2011, on a consolidated basis, was $704.9 million for PNMR. At November 1, 2011, PNMR had invested cash of $166.7 million. PNM and TNMP had no such investments.

As of November 1, 2011, PNM and TNMP had $63.8 million and $5.4 million in borrowings from PNMR under their intercompany loan agreements, but had no such borrowings as of September 30, 2011.

Financing Activities

In March 2009, TNMP entered into and borrowed $50.0 million under a loan agreement with Union Bank, N. A. (the “2009 Term Loan Agreement”).  Through hedging arrangements, TNMP established fixed interest rates for the 2009 Term Loan Agreement of 6.05% for the first three years and 6.30% thereafter. In January 2010, the relationship was modified to reduce the fixed interest rate to 4.80% through March 31, 2012 and to 5.05% thereafter. This hedge was accounted for as a cash-flow hedge and the December 31, 2010 pre-tax fair value of $1.9 million was included in other current liabilities, except for $0.8 million included in other deferred credits, and in AOCI. Amounts reclassified from AOCI are included in interest charges. The fair value determinations were made using Level 2 inputs under GAAP and were determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.  

On September 30, 2011, TNMP entered into and borrowed $50.0 million under a Term Loan Credit Agreement (the "2011 Term Loan Agreement") with JPMorgan Chase Bank, N.A. Borrowings under this agreement must be repaid by June 30, 2014 and are secured by $50.0 million aggregate principal amount of first mortgage bonds of TNMP (the "Series 2011 A Bonds"). TNMP entered into hedging agreements whereby it effectively established fixed interest rates for such borrowing of 1.475% through March 30, 2014 and 1.985% thereafter, which is an effective rate of 3.566% over the life of the debt considering the amounts paid to exit the prior arrangements and enter into the new arrangements. The hedging obligations entered into in connection with the 2011 Term Loan Agreement are also secured by the Series 2011 A Bonds. This hedge is accounted for as a cash-flow hedge and had a zero fair value at September 30, 2011, using Level 2 inputs under GAAP. The 2011 Term Loan Agreement replaces the 2009 Term Loan Agreement. On September 30, 2011, TNMP repaid all amounts outstanding under the 2009 Term Loan Agreement and related hedging agreements.

On October 6, 2011, PNM priced a public offering of $160.0 million aggregate principal amount of its 5.35% Senior Unsecured Notes due 2021. The bonds were offered at 99.857% of face amount and the offering closed on October 12, 2011. The notes bear interest at a rate of 5.35% per annum, payable semi-annually on April 1 and October 1 of each year, beginning on April 1, 2012, and will mature on October 1, 2021. Proceeds from the offering were used to repay outstanding borrowings under the PNM Facility.

On October 24, 2011, PNMR commenced a cash tender offer to purchase up to $50.0 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015. The price PNMR is offering to pay for the notes is their principal amount plus a premium of up to 17%, depending on when the notes are tendered, plus accrued and unpaid interest. The tender offer is scheduled to expire on November 21, 2011. If the tender offer is successful, PNMR will use a portion of the proceeds from the sale of First Choice (see Note 16) to fund the purchase.

Convertible Preferred Stock

On September 23, 2011, PNMR entered into an agreement to purchase of all of its outstanding convertible preferred stock, Series A (the “Preferred Stock”) pursuant to a Sale and Purchase Agreement dated September 23, 2011 between PNMR and Cascade. Cascade owned all of the 477,800 outstanding shares of Preferred Stock, which were convertible into 4,778,000 shares of PNMR common stock. Upon signing, the agreement obligated PNMR to purchase the Preferred Stock at a 2% discount from a price determined by the daily volume weighted average price per share of PNMR's common stock for the ten trading days ending on September 30, 2011 times the number of shares of PNMR common stock into which the Preferred Stock was convertible. The

46

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

purchase of the Preferred Stock closed on October 5, 2011 with PNMR paying Cascade $73.5 million. The difference between the purchase price and the $100.0 million carrying value of the Preferred Stock is reflected as an addition to common stock in the accompanying Condensed Consolidated Financial Statements. PNMR utilized a borrowing under its revolving credit facility to fund the purchase of the Preferred Stock. Such borrowing was repaid on November 1, 2011 with a portion of the proceeds from the sale of First Choice (see Note 16).

PNMR issued the Preferred Stock in November 2008. The Preferred Stock was entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the Preferred Stock had been converted into common stock. The Preferred Stock was entitled to vote on all matters voted upon by common stockholders, except for the election of the Board. In the event of liquidation of PNMR, preferred holders would have received a preference of $0.10 per common share equivalent. After that preference, common holders would have received an equivalent liquidation preference per share and all remaining distributions would have been shared ratably between common and preferred holders using the number of shares of common stock into which the Preferred Stock was convertible. The terms of the Preferred Stock resulted in it being substantially equivalent to common stock. Therefore, for earnings per share purposes the number of common shares into which the Preferred Stock was convertible was included in the weighted average number of common shares outstanding for periods prior to September 23, 2011. Similarly, dividends on the Preferred Stock were considered to be common dividends in the accompanying Condensed Consolidated Financial Statements.

(8) 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.

Information concerning pension and other postretirement plans is contained in Note 12 of Notes to Consolidated Financial Statements in the 2010 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 table presents the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	65		$	105		$	—	$	—
Interest cost	8,202			8,518			1,345			1,913			233		263
Long-term return on plan assets	(9,269		)	(9,339		)	(1,347		)	(1,393		)	—		—
Amortization of net loss	2,302			1,613			801			1,372			23		18
Amortization of prior service cost	79			79			(662		)	(1,036		)	—		—
Net periodic benefit cost	$	1,314		$	871		$	202		$	961		$	256	$	281

47

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	Nine Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	195		$	314		$	—	$	—
Interest cost	24,606			25,555			4,035			5,738			699		790
Long-term return on plan assets	(27,807		)	(28,016		)	(4,041		)	(4,179		)	—		—
Amortization of net loss	6,906			4,838			2,403			4,116			69		53
Amortization of prior service cost	237			238			(1,986		)	(3,107		)	—		—
Net periodic benefit cost	$	3,942		$	2,615		$	606		$	2,882		$	768	$	843

PNM made contributions to its pension plan trust of $20.5 million and $34.0 million in the three months and nine months ended September 30, 2011 and $6.5 million and $13.1 million in the three months and nine months ended September 30, 2010. PNM anticipates making additional contributions of $7.5 million in 2011.  Based on current law and estimates of portfolio performance, PNM estimates making contributions to its pension plan trust that total $163.9 million for 2012- 2015. The estimated contributions were developed using estimated discount rates and expected returns on assets to calculate the pension liabilities. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate and return on assets. PNM contributed $0.7 million and $1.9 million to the trust for other postretirement benefits for the three months and nine months ended September 30, 2011 and $0.4 million and $1.6 million for the three months and nine months ended September 30, 2010. PNM expects contributions during 2011 to the trust for other postretirement benefits to total $2.6 million.  Disbursements under the executive retirement program, which are funded by the Company and considered to be contributions to the plan, were $0.4 million and $1.2 million in the three months and nine months ended September 30, 2011 and $0.4 million and $1.1 million in the three months and nine months ended September 30, 2010 and are expected to total $1.5 million during 2011.

TNMP Plans

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

	Three Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	77		$	72		$	—	$	—
Interest cost	951			1,032			163			178			12		13
Long-term return on plan assets	(1,368		)	(1,449		)	(133		)	(129		)	—		—
Amortization of net (gain) loss	86			—			(48		)	(49		)	—		(1		)
Amortization of prior service cost	—			—			15			15			—		—
Net Periodic Benefit Cost (Income)	$	(331	)	$	(417	)	$	74		$	87		$	12	$	12

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	Nine Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	231		$	217		$	—	$	—
Interest cost	2,853			3,095			489			533			36		39
Long-term return on plan assets	(4,104		)	(4,346		)	(399		)	(386		)	—		—
Amortization of net (gain) loss	258			—			(144		)	(147		)	—		(3		)
Amortization of prior service cost	—			—			45			45			—		—
Net Periodic Benefit Cost (Income)	$	(993	)	$	(1,251	)	$	222		$	262		$	36	$	36

TNMP made contributions to its pension plan trust of $0.8 million and $1.0 million in the three months and nine months ended September 30, 2011 and $0.2 million in the three months and nine months ended September 30, 2010. TNMP anticipates making additional contributions of $0.2 million in 2011. Based on current law and estimates of portfolio performance, TNMP estimates making contributions to its pension plan trust that total $6.0 million for 2012-2015. The estimated contributions were developed using estimated discount rates and expected returns on assets to calculate the pension liabilities. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate and return on assets. TNMP contributed zero and $0.4 million to the trust for other postretirement benefits for the three months and nine months ended September 30, 2011 and zero and $0.6 million for the three months and nine months ended September 30, 2010. TNMP does not expect to make additional contributions during 2011 to the trust for other postretirement benefits. Disbursements under the executive retirement program, which are funded by the Company and considered to be contributions to the plan, were less than $0.1 million in the three months and nine months ended September 30, 2011 and 2010 and are expected to total $0.1 million during 2011.

(9)    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 is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. The Company is also involved in various legal 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 proceedings on its financial position, results of operations, or cash flows. It is the Company's policy to accrue for expected liabilities in accordance with GAAP when it is probable that a liability has been incurred and the amount to be incurred is reasonably estimable. 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, although the outcome of litigation, investigations, and other legal proceedings is inherently uncertain.

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, is not reasonably estimable. 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 subject to the known uncertainty of litigation. The Company has recorded 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.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Additional information concerning commitments and contingencies is contained in Note 16 of Notes to Consolidated Financial Statements in the 2010 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, and the DOE is required 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. 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. Such estimate reflects the impact of the extension of the PVNGS operating licenses discussed in Note 13 below. PNM accrues these costs as a component of fuel expense, meaning that the charges are accrued as the fuel is consumed. At September 30, 2011 and December 31, 2010, PNM recorded interim storage costs of $14.5 million and $14.8 million in other deferred credits.

The Clean Air Act

Regional Haze

EPA has established rules addressing regional haze and guidelines for BART determinations. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. In particular, the rules define how an SO₂ emissions trading program developed by the Western Regional Air Partnership, a voluntary organization of western states, tribes, and federal agencies, can be used by western states. New Mexico will be participating in the SO₂ program, which is a trading program that will be implemented if SO₂ reduction milestones are not met.

SJGS

In November 2006, the NMED requested a BART analysis for NOx and particulates for each of the four units at SJGS. PNM submitted its analysis to the NMED in June 2007, recommending against installing additional pollution control equipment on any of the SJGS units beyond those planned at that time, the installation of which was completed in March 2009. PNM subsequently provided additional data in response to requests from the NMED. On June 21, 2010, the NMED filed its proposed regional haze SIP with the EIB. The NMED filing included a finding by the NMED that BART for NOx at SJGS is a technology known as “selective catalytic reduction” (“SCR”) plus “sorbent injection.” PNM disagreed with this proposed BART determination.

As part of its 2007 submission, PNM identified additional control technology alternatives, including SCR, to already planned pollution control equipment upgrades and evaluated the feasibility of these technologies for the purpose of reducing visibility impacts in accordance with EPA's "Guidelines for BART Determinations under the Regional Haze Rules" (“BART Guidelines”). PNM concluded that SCR was not appropriate as BART. In 2010, using EPA's BART Guidelines, PNM estimated the installation of SCR technology at SJGS would cost approximately $750 million to $1 billion for the entire station, of which PNM's share would be 46.3% based on its SJGS ownership percentage. The SCR technology would also increase operating costs at SJGS.

In July 2011, PNM received a detailed conceptual design and cost estimate for installation of SCR at SJGS from an independent engineering design firm. Unlike the analysis prepared in 2007, the July 2011 analysis is based on quantity take-off estimates from the conceptual design that this engineering firm was in the process of developing. A cost estimate based on this work was submitted to EPA on July 20, 2011. Although there are certain differences between the two analyses, the July 2011 cost estimate is consistent with PNM's earlier BART analysis cost estimate range and continues to support PNM's contention that EPA's SCR cost estimates are unrealistically low.

Under a consent decree it signed with WildEarth Guardians in 2010, EPA was required to issue a proposed FIP regarding interstate transport for certain states, including New Mexico, by November 11, 2010, which was later extended to December 22, 2010, if no proposed SIP had been submitted. Interstate transport requires states to have adequate provisions to avoid interfering with the air quality implementation plans developed in other states. A separate section of the CAA regulates “regional haze,”

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

which requires states to identify certain facilities that impact visibility in the 156 Class I areas (national parks and wilderness areas). Once identified, states determine the types of emission controls that should be installed as BART at those facilities to reduce the visibility impairing pollutants. EPA Region 6 issued a proposed interstate transport FIP, which was published in the Federal Register on January 5, 2011. The proposed FIP also included a regional haze BART determination for NOx controls at SJGS that requires SCR installation on all four units within three years of the final order, rather than the five-year implementation schedule the regional haze rules generally allow and that EPA proposed for Four Corners. The proposed FIP did not require sorbent injection. The proposed FIP provided for a proposed emission limit for NOx at SJGS of 0.05 pounds per MMBTU, whereas EPA's proposed emission limit for NOx at Four Corners is 0.098 pounds per MMBTU. The public comment period on the proposed FIP ended on April 4, 2011. The deadline for issuance of the final FIP was extended to August 5, 2011 pursuant to an agreement between EPA and WildEarth Guardians.

NMED withdrew its June 21, 2010 proposed regional haze SIP on December 17, 2010. On February 28, 2011, the NMED filed a new petition with the EIB to consider both an interstate transport SIP and a regional haze SIP. Among other things, the draft regional haze SIP concludes that selective non-catalytic reduction (“SNCR”) controls are regional haze BART for SJGS. SNCR controls meet EPA's presumptive NOx BART limit of 0.23 pounds per MMBTU for wall-fired boilers burning sub-bituminous coal. The proposed SIP required installation of SNCR controls within five years. PNM estimates the installation of SNCR technology at SJGS would cost approximately $77 million for the entire station, of which PNM's share would be 46.3%. The EIB approved the NMED's proposed regional haze and interstate transport SIPs in June 2011 upon conclusion of public hearings and the Governor of New Mexico submitted the SIPs to EPA in June 2011, which EPA received in July 2011.

PNM filed extensive technical and legal comments on the proposed FIP with EPA, including a statement in support of the then-draft SIP. As noted, the EIB approved SIP was received by EPA in July 2011. PNM believed that EPA must consider that SIP under the CAA, which requires EPA to give deference to a state's conclusions with respect to its air quality. Only the interstate transport rule was subject to the August 5, 2011 court-ordered deadline for a final FIP. In order to meet that deadline and at the same time give due consideration to the SIP, the Governor of New Mexico requested that EPA finalize the FIP associated with the interstate transport rule by August 5, 2011 and stay any action on the proposed FIP for regional haze until New Mexico's SIP revisions had been fully considered and either approved or disapproved. Nevertheless, on August 5, 2011, EPA issued its final FIP on both interstate transport and regional haze, which requires installation of SCR technology at SJGS and allows for a five-year implementation schedule. The final FIP was published in the Federal Register in August 2011 and became effective on September 21, 2011. The final FIP provides for an emission limit for NOx at SJGS of 0.05 pounds per MMBTU, including startup, shutdown, and malfunction emissions which were not included in the draft FIP. On September 16, 2011, PNM filed a Petition for Review of EPA's final FIP determination in the United States Court of Appeals for the Tenth Circuit. On the same day and pursuant to the Administrative Procedures Act, PNM filed a Request for a Stay of the effective date of the final BART determination pending judicial review with EPA. PNM filed a Petition for Reconsideration of the rule and a Request to Stay the effective date of the final BART FIP under the CAA with EPA on October 21, 2011. Neither the Petition in the Tenth Circuit, nor the Petition for Reconsideration by EPA delays the implementation timeframe unless a stay is granted. WildEarth Guardians filed a separate appeal against EPA challenging the five-year, rather than three-year, implementation schedule. PNM was granted leave to intervene in that appeal. WildEarth Guardians, Dine Citizens against Ruining our Environment, National Parks Conservation Association, New Energy Economy, San Juan Citizens Alliance, and Sierra Club sought, and were granted, leave to intervene in PNM's appeal. On October 21, 2011, the Governor of New Mexico and the NMED filed a Petition for Review of EPA's final FIP determination in the Tenth Circuit and a Petition for Reconsideration of the rule with EPA.

As stated above, PNM believes that SCR technology is not appropriate for BART at SJGS and that the state's SIP which calls for SNCR provides reasonable progress towards visibility improvements required under the CAA and EPA rules. EPA indicated on August 5, 2011, that it would continue to review the state's SIP but that EPA had already evaluated SNCR as part of the FIP and had ruled SNCR out as BART for San Juan.

Although PNM is challenging EPA's decision, the five-year compliance deadline requires PNM to take immediate steps to commence the installation of SCR, which is a large construction project requiring extensive advance planning. Accordingly, PNM plans to issue as soon as possible a RFP to prospective bidders for the installation of SCR. In connection with this process, PNM has, with the assistance of a leading engineering firm, further refined the conceptual design and cost estimates for the installation of SCR at SJGS. The current estimate for such construction is in the range of approximately $749 million to $897 million, exclusive of AFUDC, which at the lower range would be approximately $38 million and at the upper range would be approximately $45 million.

51

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM will seek recovery from its ratepayers of all costs that may ultimately be incurred as a result of the final FIP. While PNM cannot accurately predict the impact of these requirements on PNM's ratepayers until requirements, if any, are finalized, it estimates that the installation of SCR controls would cost the average residential PNM customer up to approximately $85 for the first yearwith slowly declining costs during the period of depreciation of the SCR and that costs to businesses would be higher.

On January 19, 2011, multiple parties filed with EPA a NOI to sue under the CAA for EPA's failure to promulgate a FIP within two years of a finding that certain states, including New Mexico, had failed to make all or part of a required regional haze SIP submittal. The NOI alleges that the deadline for final promulgation of regional haze FIPs or full approval of regional haze SIPs was January 15, 2011. The same parties also filed a separate NOI to sue under the CAA for EPA's failure to take final action on SIP submissions by multiple states, including New Mexico, within 18 months of receipt of submission.

PNM is unable to predict the ultimate outcome of these matters or what, if any, additional pollution control equipment will ultimately be required or approved for installation for SJGS. If additional equipment is required and/or final requirements result in additional operating costs to be incurred, PNM believes that its access to the capital markets are sufficient to be able to finance the installation and that equipment and financing costs should be recoverable through the ratemaking process and would seek recovery of them. However, PNM can provide no assurance that all such amounts will be recovered from ratepayers. It is possible thatrequirements to comply with the final BART determinations, 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 of individual participants to continue participation in the plant.

Four Corners

EPA Region 9 previously requested that APS, as the operating agent for Four Corners, perform a BART analysis for Four Corners. APS submitted an analysis to EPA concluding that certain combustion control equipment constitutes BART for Four Corners. Based on the analyses and comments received through EPA's rulemaking process, EPA will determine what it believes constitutes BART for Four Corners.

On October 6, 2010, EPA issued its proposed BART determination for Four Corners. The rule, as proposed, would require the installation of SCR as post-combustion controls on each of Units 1-5 at Four Corners to reduce NOx emissions. As previously disclosed, PNM estimates its total costs could be up to approximately $69.0 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. EPA proposed a 10% stack opacity limitation for all five units and a 20% opacity limitation on certain fugitive dust emissions, although the proposed fugitive dust provision is unrelated to BART.

SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the coal-fired plant. On November 8, 2010, 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. Completion of the purchase by APS, which is expected to occur in the second half of 2012, is subject to the receipt of various regulatory approvals. Closing is also conditioned on the execution of a new coal supply contract for the lease renewal period described in Note 13 and other conditions. Pursuant to an agreement among the Four Corners participants, the other participants had a right of first refusal to purchase shares of SCE's interests proportional to their current ownership percentages. The exercise of this purchase right expired on March 8, 2011 and neither PNM nor any of the other participants exercised this right. APS has announced that, if APS's purchase of SCE's interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2, and 3 at the plant (PNM has no ownership interest in Four Corners Units 1, 2, and 3).

On November 24, 2010, APS submitted a letter to EPA proposing an alternative to EPA's October 2010 BART proposal. Specifically, APS proposed to close Four Corners Units 1, 2, and 3 by 2014 and to install post-combustion pollution controls for NOx on Units 4 and 5 by the end of 2018, provided that EPA agrees to a contemporaneous resolution of Four Corners' obligations or liability, if any, under the regional haze and reasonably attributable visibility impairment programs, the NSR program, and NSPS programs of the CAA.

On February 10, 2011, EPA signed a Supplemental Notice Requesting Comment, related to the BART rulemaking for Four Corners. In the Supplemental Notice, EPA proposed to find that a different alternative emission control strategy, based upon

52

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

APS's November 2010 proposal, would achieve more progress than EPA's October 2010 BART proposal. The Supplemental Notice proposes that Units 1, 2, and 3 would close by 2014, post-combustion pollution controls for NOx would be installed on Units 4 and 5 by July 31, 2018, and the NOx emission limitation for Units 4 and 5 would be 0.098 lbs/MMBtu, rather than the 0.11 lbs/MMBtu proposed by EPA in October 2010. EPA proposals are subject to public comment. On July 15, 2011, various environmental groups filed a NOI to sue EPA because it failed to promulgate regional haze FIPs for Four Corners and Navajo Generating Station. PNM is not an owner of Navajo Generating Station. The NOI states that EPA has failed to fulfill its nondiscretionary duty under the CAA to submit a BART determination for the plants without unreasonable delay. The CAA requires parties to give EPA 180 days' notice before commencing a lawsuit based on allegations that EPA unreasonably delayed performance of a nondiscretionary act.

In addition, on February 16, 2010, a group of environmental organizations filed a petition with the DOI and DOA requesting those agencies to certify to EPA that visibility impairment in sixteen national park and wilderness areas is reasonably attributable to emissions from Four Corners and other plants. If the agencies certify impairment, EPA is required to evaluate and, if necessary, determine BART for Four Corners under a different haze program known as “Reasonably Attributable Visibility Impairment.” On January 19, 2011, a similar group of environmental organizations filed a lawsuit against the DOI and DOA, alleging among other things that the agencies failed to act on the February 2010 petition “without unreasonable delay” and requesting the court to order the agencies to act on the petition within 30 days. On June 30, 2011, the court issued its opinion dismissing the plaintiffs' claims explaining that because the DOI and DOA reached a “definitive decision” to deny the plaintiffs' petitions, the court is unable to grant further relief to the plaintiffs and, therefore, their claims must be dismissed as moot.

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, the result of the lawsuit mentioned above, 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 proposed BART determination for Four Corners. As proposed, the participant owners of Four Corners will have five years after EPA issues its final determination to achieve compliance with the BART requirements. PNM is unable to predict the ultimate outcome of this matter.

Ozone Non-Attainment

In March 2009, the NMED published its draft recommendation of area designations for the 2008 revised ozone national ambient air quality standard ("NAAQS"). The draft recommended that San Juan County, New Mexico be designated as non-attainment for ozone. SJGS is situated in San Juan County. However, the NMED subsequently determined that the monitor indicating high ozone levels was not reliable and did not recommend to EPA that San Juan County be designated as non-attainment. On January 6, 2010, EPA announced it would strengthen the 8-hour ozone standard by setting the standard in a range of 0.060-0.070 parts per million (“ppm”). EPA had intended to establish a new ozone standard by July 31, 2011. However, on September 2, 2011, President Obama requested that the EPA administrator withdraw the agency's proposed rule that would have replaced the existing ozone NAAQS.   The President in his release stated that work is already underway to reconsider the ozone standard in 2013.  Depending upon where the standard is set in the 2013 reconsideration of the ozone standard, San Juan County could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county back into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone in the presence of sunlight. As a result, SJGS could be required to put on additional NOx controls. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter 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 the SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes a provision whereby stipulated penalties are assessed 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 for each quarter. Over the past several years, PNM has also submitted reports addressing mercury and NOx emission controls for SJGS as required by the Consent Decree. Plaintiffs and NMED rejected PNM's reports. PNM disputes the validity of the rejection of the reports. On May 17, 2010, PNM filed a petition with the federal district court seeking a judicial determination on the dispute

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(Unaudited)

relating to PNM's mercury controls. NMED and plaintiffs seek to require PNM to implement mercury controls that PNM estimates would increase annual mercury control costs for the entire station by as much as $42 million (for a total annual mercury control cost of $47 million). The court held a status conference on November 29, 2010 for purposes of establishing the appropriate process for resolution of the outstanding disputes related to this matter and to discuss other issues raised in PNM's petition and has tentatively selected a special master to evaluate the technical arguments in the case. PNM cannot predict the outcome of this matter.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government as well as a lease from the Navajo Nation. The Navajo Acts, enacted in 1995 by the Navajo Nation, 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, Window Rock District, challenging the applicability of the Navajo Acts to Four Corners. The District Court stayed these proceedings pursuant to a request by the parties and the parties are seeking to negotiate a settlement.

In 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations.Each of the Four Corners participants filed a petition with the Navajo Nation Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the outcome of the settlement negotiations mentioned above.

In May 2005, APS and the Navajo Nation signed a Voluntary Compliance Agreement resolving the dispute regarding 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.

The Company cannot currently predict the outcome of these matters or the range of their potential impacts.

Section 114 Request

On April 6, 2009, APS received a request from EPA under Section 114 of the CAA seeking detailed information regarding projects at and operations of Four Corners. This request is part of an enforcement initiative that EPA has undertaken under the CAA. EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the CAA. Other electric utilities have received and responded to similar Section 114 requests, and several of them have been subject to notices of violation and lawsuits by EPA. 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 New Source Review

On May 7, 2010, APS received a NOI to sue from EarthJustice, on behalf of several environmental organizations, related to alleged violations of the CAA at Four Corners.  The NOI alleges NSR related violations and NSPS violations.  Under the CAA, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit.  Within that 60-day time period, EPA may step in and file a lawsuit regarding the allegations. If EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in EPA's lawsuit, if it so desires.  The 60-day period lapsed in July 2010, and EPA did not take any action. 

On September 2, 2011, APS received a second NOI to sue from EarthJustice, on behalf of the same environmental organizations. The September 2, 2011 notice is virtually identical to the May 2010 Notice and alleges violations of the NSR and NSPS programs.

On October 3, 2011, EarthJustice filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants, except PNM (EarthJustice filed suit against PNMR, which is not a Four Corners participant), alleging violations of the PSD provisions of the CAA. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. APS is evaluating the lawsuit. PNMR has not been served with this lawsuit.

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(Unaudited)

On October 26, 2011, APS received a third NOI to sue from EarthJustice, on behalf of the same environmental organizations. The third notice is also virtually identical to the prior notices, as well as to the claims in the October 3, 2011 lawsuit.

At this time, PNM cannot predict the ultimate outcome of this matter. 

Review of New Sources and Modifications in Indian Country

Pursuant to its authority under the CAA, in June 2011, EPA finalized a FIP, which puts in place a pre-construction air permitting program for construction of new and modified small facilities and minor modifications of existing facilities in Indian country.  The FIP will require a source owner or operator to apply for a permit before building a new facility or modifying an existing one if it is determined that the proposed project will increase emissions above any of the minor NSR thresholds included in the rule.  Among other things, sources triggering the rule's source-specific permit requirements will be required to undergo a case-by-case control technology review and, potentially, an air impact quality analysis.  APS and PNM are currently evaluating the potential impact of this rule on Four Corners, which is located on Indian lands.

Endangered Species Act

On January 30, 2011, the Center for Biological Diversity, Dine Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit against the OSM and the DOI, alleging that OSM failed to engage in mandatory Endangered Species Act (“ESA”) consultation with the 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 requests 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.  PNM is not a party to the lawsuit. APS has intervened in the lawsuit and is evaluating the lawsuit to determine its potential impact on Four Corners operations.  PNM is unable to predict the ultimate outcome of this matter.

Cooling Water Intake Structures

EPA issued its proposed cooling water intake structures rule on April 20, 2011, which would provide national standards applicable to certain cooling water intake structures at existing power plants and other facilities pursuant to the Clean Water Act. The proposed standards are intended 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). To minimize impingement mortality, 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. To minimize entrainment mortality, 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 is subject to a public comment period, which was extended to August 18, 2011. EPA is expected to issue a final rule by July 2012. As proposed, existing facilities subject to the rule would have to comply with the impingement mortality requirements as soon as possible, but in no event later than eight years after the effective date of the rule, and would have to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. PNM and APS are performing analyses to determine the 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.

Santa Fe Generating Station

PNM and the NMED conducted investigations of gasoline and chlorinated solvent groundwater contamination detected beneath the site of the former Santa Fe Generating Station to determine the source of the contamination pursuant to a 1992 settlement agreement between PNM and the NMED.

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(Unaudited)

PNM believes that the data compiled indicates observed groundwater contamination originated from off-site sources. However, to avoid a prolonged legal dispute, PNM entered into settlement agreements with the NMED under which PNM agreed to install a remediation system to treat water from a City of Santa Fe municipal supply well and install an additional extraction well and two new monitoring wells to address gasoline contamination in the groundwater at and in the vicinity of the site. PNM will continue to operate the remediation facilities until the groundwater meets applicable federal and state standards or until such time as the NMED determines that additional remediation is not required, whichever is earlier. The well continues to operate and meets federal drinking water standards. PNM is not able to assess the duration of this project.

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. The Company is unable to predict the outcome of this matter.

Coal Combustion Waste Disposal

Regulation

SJCC currently disposes of CCBs consisting of fly ash, bottom ash, and gypsum from SJGS 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 at the mine with federal oversight by the OSM. APS currently 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 the Four Corners plant is regulated by EPA and the New Mexico State Engineer's Office. 

On May 4, 2010, EPA issued a proposed rulemaking to regulate CCBs.  The proposal asks for public comment on two approaches for regulating CCBs. One option is to regulate CCBs under Subtitle C of the RCRA as a hazardous waste which allows EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs under RCRA Subtitle D as a non-hazardous waste. This provides 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. EPA has indicated that it will work with the OSM to develop federal regulations for placement of CCBs in minefill operations. The proposed rule also states that EPA and OSM will consider the recommendations of the National Research Council, which, at the direction of Congress, studied the health, safety, and environmental risks associated with the placement of CCBs in U.S. coal mines.  The 2006 report concluded that the “placement of coal combustion residues in mines as part of coal mine reclamation may be an appropriate option for the disposal of this material.” On June 21, 2010, EPA published the proposed rule in the Federal Register. The public comment period on the proposed rule ended November 19, 2010. A final rule regarding waste designation for coal ash is not expected from EPA before mid to late 2012.

The OSM had initially drafted a CCB mine placement rule in late summer 2008, but with the then-impending change in federal administration, the Office of Management and Budget at the White House returned the rule to OSM for re-submittal under the incoming administration. An OSM CCB rulemaking team has been formed to develop a proposed rule. OSM's draft rulemaking schedule targets an April 2012 publication in the Federal Register.

PNM advocates for the non-hazardous regulation of CCBs under Subtitle D of RCRA. PNM is encouraged by EPA's proposed decision to develop separate federal regulations in conjunction with the OSM's intent to develop regulations for mine placement of CCBs. PNM believes regulatory oversight for this matter should come from the OSM and state mining and mining reclamation agencies. In addition, PNM believes the decision by EPA to consider the conclusions of the National Research Council study in the development of federal regulations regarding placement of CCBs in minefilling operations is a prudent one. 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. 

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(Unaudited)

Sierra Club Allegations

In December 2009, PNM and PNMR received a NOI to sue (“RCRA Notice”) under RCRA from the Sierra Club.  The RCRA Notice was also sent to all SJGS owners, to SJCC, which operates the San Juan Mine that supplies coal to SJGS, and to BHP. Additionally, PNM was informed that SJCC and BHP received a separate NOI to sue under the Surface Mine Control and Reclamation Act ("SMCRA") from the Sierra Club. On April 8, 2010, the Sierra Club filed suit in the U.S. District Court for the District of New Mexico against PNM, PNMR, SJCC, and BHP. In the suit, the Sierra Club alleges that activities at SJGS and the San Juan Mine are causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCBs at the San Juan Mine constitutes "open dumping" in violation of RCRA.  The claims under RCRA are asserted with respect to PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA, which are directed only against SJCC and BHP. The complaint requests judgment for the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCBs at the mine or to cease placement of CCBs at the mine; the imposition of civil penalties; and an award of plaintiff's attorney's fees and costs. On July 10, 2010, the Sierra Club filed an amended complaint that corrected some technical deficiencies in its original complaint. The factual allegations remained the same. The parties have agreed to a stay of the action, which the Court entered on August 27, 2010, to allow the parties to try to address Sierra Club's concerns. If the parties are unable to settle the matter, PNM is prepared to aggressively defend its position in the RCRA litigation.PNM and PNMR cannot predict the outcome of this matter or the range of potential outcomes at the present time.

Gila River Indian Reservation Superfund Site

In April 2008, EPA informed PNM that it may be a PRP in the Gila River Indian Reservation Superfund Site in Maricopa County, Arizona. PNM, along with SRP, APS, and EPE, owns a parcel of property on which a transmission pole and a portion of a transmission line are located. The property abuts the Gila River Indian Community boundary and, at one time, may have been part of an airfield where crop dusting took place. EPA has settled the matter with the PRPs for past cleanup-related costs involving contamination from the crop dusting. PNM's share of the settlement was less than $0.1 million.

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, 2011 and December 31, 2010, prepayments for coal, which are included in other current assets, amounted to $17.8 million and $30.9 million. SJCC holds certain federal, state, and private coal leases under an underground coal sales agreement pursuant to which it will supply processed coal for operation of the SJGS through 2017. The coal agreement is a cost plus contract. SJCC is reimbursed for all costs for mining and delivering the coal plus an allocated portion of administrative costs. In addition, SJCC 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 approximately 44.2 million tons of coal during its remaining term, which would supply substantially all the requirements of the SJGS through approximately 2017.

APS purchases all of Four Corners' coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016 with pricing determined using an escalating base-price. APS is currently in discussions with the coal supplier regarding post-2016 coal supply for Four Corners.

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 most recent estimates, the final costs of mine reclamation, net of contract buyout costs paid to SJCC and reclamation payments made through September 30, 2011, are estimated to be $53.4 million for the surface mines at both SJGS and Four Corners and $21.7 million for the underground mine at SJGS, in future dollars. PNM made payments against the surface mine liability of $1.3 million and $3.6 million during the three and nine months ended September 30, 2011 and $0.9 million and $3.5 million during the three and nine months ended September 30, 2010. As of September 30, 2011 and December 31, 2010, obligations of $23.7 million and $25.0 million for surface mine reclamation and $3.0 million and $2.8 million for underground mining activities were recorded in other deferred credits.

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(Unaudited)

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 and has since been on-site. On September 12, 2011, SJCC informed PNM that the fire was extinguished and continues to report that all measurements from the area of the fire continue to suggest the fire is extinguished. However, MSHA requires sealing the incident area and confirming a noncombustible environment before MSHA will allow re-entry of the mine. SJCC informed PNM that MSHA approved a sealing plan on October 6, 2011. SJCC has indicated to PNM that it believes the mine’s longwall equipment has experienced only minor damage, if any, and currently estimates being able to restart longwall mining operations approximately April 1, 2012.

PNM continues to actively monitor developments at the mine and evaluate the availability of coal supply. As of September 9, 2011, there were inventories of previously mined coal available to supply the fuel requirements of SJGS for approximately eight and one-half months at forecasted consumption before the disruption. Production from continuous miner sections may be possible before the longwall mining operations resume, perhaps as soon as mid-November, and coal sourced from other mines is being considered to supplement inventories. SJCC has also reported it is implementing cost savings measures during the mine disruption and PNM is working with SJCC to identify cost-saving opportunities to mitigate the impact of the incident.

PNM anticipates that as the cost of the mine recovery flows through the cost-reimbursable component of the coal supply agreement, it would recover the portion of such costs attributable to its customers subject to New Mexico regulation through its FPPAC. PNM is unable at this time to predict when operations will resume at the mine. Based on information PNM has received from SJCC to date, PNM does not expect the mine fire to have a material effect on its financial condition, results of operations, or cash flows due to the inventories of previously mined coal available to supply SJGS. However, if the mine is shut down longer than currently anticipated, 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.

PVNGS Liability and Insurance Matters

The PVNGS participants have insurance for public liability exposure for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, the PVNGS participants maintain the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 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. The maximum assessment per reactor under the program for each nuclear incident is $117.5 million, subject to an annual limit of $17.5 million per incident, to be periodically adjusted for inflation. Based on PNM's 10.2% interest in the three PVNGS units, PNM's maximum potential assessment per incident for all three units is $36.0 million, with an annual payment limitation of $5.4 million.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for property 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. The property damage and decontamination coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). PNM is subject to retrospective assessments under all NEIL policies if NEIL's losses in any policy year exceed accumulated funds. The maximum amount PNM could incur under the current NEIL policies totals $5.8 million for each retrospective assessment declared by NEIL's Board of Directors due to losses. The insurance coverage discussed in this and the previous paragraph is 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, Valencia, Afton, Luna, and Lordsburg. Water availability does not appear to be an issue for these plants at this time.

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(Unaudited)

Severe drought, such as that which occurred during 2002 in the “four corners” region of New Mexico where SJGS and Four Corners are located, can affect the availability of these plants. In future years, if adequate precipitation is not received in the watershed that supplies the four corners region, the plants could be impacted. Consequently, PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines. 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. The current agreements run through December 31, 2012. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement on a long-term supplemental contract relating to water for SJGS and Four Corners with the Jicarilla Apache Nation that runs through 2016. Although the Company does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather situation or its ramifications, or how policy, regulations, and legislation may impact the Company 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 the next forty years.

PVNGS Water Supply Litigation

A summons was served on APS in 1986 that required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons. APS' rights and the rights of the other PVNGS participants to the use of groundwater and effluent at PVNGS are potentially at issue in this action. 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 both of 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 entitled “State of New Mexico v. United States, et al.”, in the District Court of San Juan County, New Mexico, to adjudicate all water rights in the San Juan River Stream System. PNM was made a defendant in the litigation in 1976. The action is expected to adjudicate water rights used at Four Corners and at SJGS. In 2005, the Navajo Nation and various parties announced a settlement of the Navajo Nation's surface water rights. On March 30, 2009, President Obama signed legislation confirming the settlement with the Navajo Nation.

The United States, the State of New Mexico, and the Navajo Nation have entered into a water rights settlement agreement and the court recently announced the initiation of a new phase of this adjudication. Under the terms of the settlement agreement, the Navajo 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 first in an expedited inter se proceeding. The Court held a scheduling conference on October 3, 2011 and has issued a scheduling order. A second scheduling conference will be conducted on January 9, 2012 to address discovery and the remainder of pretrial proceedings.

PNM's water rights in the San Juan Basin may be affected by the rights recognized as owned by the Navajo Nation in the settlement agreement, and PNM has elected to participate in this proceeding.  It is unknown at the present time how PNM will respond to the claims made in the proposed decrees, although the claims recognized as owned by the Navajo Nation in the settlement agreement and the proposed decrees constitute a significant portion of the water available from sources on the San Juan River and in the San Juan Basin.

The Company 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.

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(Unaudited)

Conflicts at San Juan Mine Involving Oil and Gas Leaseholders

SJCC, through leases with the federal government and the State of New Mexico, owns coal interests with respect to the San Juan underground mine. Certain gas producers have leases in the area of the underground coal mine and have asserted claims against SJCC that its coal mining activities are interfering with gas production. SJCC has reached settlement with several gas leaseholders and has had success in court in defeating the claims of other claimants. Several other claims and potential claimants remain. PNM cannot predict the outcome of existing or future disputes between SJCC and gas leaseholders or the range of potential outcomes.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS. PNM argued that SPS' rates for sale of interruptible energy were excessive and that SPS had been overcharging PNM for deliveries of energy through its fuel cost adjustment clause practices. PNM also intervened in a complaint proceeding brought by other customers raising similar arguments relating to SPS' fuel cost adjustment clause practices (the “Golden Spread complaint proceeding”). Additionally, in November 2005, SPS filed an electric rate case at FERC proposing to unbundle and raise rates charged to customers effective July 2006. PNM intervened in the case and objected to the proposed rate increase. In September 2006, PNM and SPS filed a settlement agreement providing for resolution of issues relating to rates for sales of interruptible energy, but not resolving the fuel clause issues. In September 2008, FERC issued its order approving the settlement between PNM and SPS.

In April 2008, FERC issued its order in the Golden Spread complaint proceeding. FERC affirmed in part and reversed in part an ALJ's initial decision, which had, among other things, ordered SPS to pay refunds to PNM with respect to the fuel clause issues. FERC affirmed the decision of the ALJ that SPS violated its fuel cost adjustment clause tariffs. However, FERC shortened the refund period applicable to the violation of the fuel cost adjustment clause issues.PNM and SPS have filed petitions for rehearing and clarification of the scope of the remedies that were ordered and reversal of various rulings in the order. FERC has not yet acted upon the requests for rehearing or clarification and they remain pending further decision. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes.

Begay v. PNM et al

A putative class action was filed against PNM and other utilities on February 11, 2009 in the United States District Court in Albuquerque. 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. Plaintiffs, including an allottee association, make broad, general assertions 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.  The plaintiffs, who have sued the defendants for breach of fiduciary duty, seek a constructive trust. They have also included a breach of trust claim against the United States and its Secretary of the Interior.  PNM and the other defendants filed motions to dismiss this action. On March 31, 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. 

On May 10, 2010, Plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs ("BIA") and are attempting to perfect such appeal through the BIA's administrative process . PNM is participating 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.

Transmission Issues

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

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TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

During the first quarter of 2011, at the request of PNM and other southwestern utilities, NERC advised all transmission owners and transmission service providers they have delayed the implementation of portions of the MOD-029 methodology for "Flow Limited" paths 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 are expecting to file a Standards Action Request later this year as a follow-up to the NERC ruling.

On April 20, 2010, Cargill Power Markets, LLC (“Cargill”) filed a complaint with FERC, asserting that PNM improperly processed its transmission service queue and unfairly invalidated a transmission service request by Cargill. On July 29, 2010, FERC issued an order and established a schedule for hearing and settlement procedures. In its order, FERC determined that PNM had improperly invalidated a single Cargill transmission service request submitted on February 21, 2008 and set the issue for hearing to determine an appropriate remedy. However, the hearing is being held in abeyance by FERC to provide time for settlement negotiations under the oversight of a FERC settlement judge. On September 27, 2010, FERC granted rehearing for further consideration. On January 13, 2011, PNM and Cargill filed a settlement agreement with FERC in which PNM agreed to pay Cargill $0.2 million and put Cargill's transmission service request back into the queue. The settlement also left Cargill's and PNM's rehearing requests in place before FERC. One intervenor in the proceeding has contested the settlement. The settlement judge reported to FERC that the settlement is contested. The settlement is before FERC for its consideration. FERC has not yet acted upon the requests for rehearing or settlement. PNM is unable to predict the final outcome of this matter at FERC.

(10) Regulatory and Rate Matters

Information concerning regulatory and rate matters is contained in Note 17 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

PNMR

First Choice Request for ERCOT Alternative Dispute Resolution

In June 2008, First Choice filed a request for alternative dispute resolution with ERCOT alleging that ERCOT incorrectly applied its protocols with respect to congestion management during the first quarter of 2008. First Choice requested that ERCOT resolve the dispute by restating certain elements of its first quarter 2008 congestion management data and by refunding to First Choice allegedly overstated congestion management charges. The amount at issue in First Choice's claim can only be determined by running ERCOT market models with corrected inputs but First Choice believes that the amount is significant. ERCOT protocols provide that ERCOT will notify potentially impacted market participants and subsequently consider the merits of First Choice's allegations. In September 2011, ERCOT forwarded information on its actions which is under review. PNMR is unable to predict the outcome of this matter. However, this matter was terminated prior to closing of the sale of First Choice (see Note 16).

PNM

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 stipulation in the 2010 Electric Rate Case discussed below as approved by the NMPRC, the parties to the stipulation, including the NMPRC staff, will jointly request that the NMPRC take no further action in this matter and close the docket. PNM anticipates this filing will be made in the fourth quarter of 2011. PNM is unable to predict the outcome of this matter.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Renewable Portfolio Standard

The REA was enacted to encourage the development of renewable energy in New Mexico. The act establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 5% of retail electric sales by January 1, 2006, increasing to 10% by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified” beginning in 2011 when no less than 20% of the renewable portfolio requirement must be met by wind energy, no less than 20% by solar energy, no less than 10% by other renewable technologies, and no less than 1.5% by distributed generation. The act provides for streamlined proceedings for approval of utilities' renewable energy procurement plans, assures utilities recovery of costs incurred consistent with approved procurement plans and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. The NMPRC has established a RCT for 2011 of 2% of all customers' aggregated overall annual electric charges that increases by 0.25% annually until reaching 3% in 2015.

In August 2010, the NMPRC partially approved PNM's revised 2010 procurement plan, including PNM's investment in 22 MW of solar PV facilities at various PNM sites and the construction of a solar-storage demonstration project. The NMPRC capped recoverable costs at a maximum of $107.7 million. Under the REA, costs incurred pursuant to and consistent with an approved procurement plan are deemed to be reasonable and recoverable in the ratemaking process. Construction of these facilities is underway, the first 17 MW of solar PV and the solar-storage demonstration project were in service at October 31, 2011, and PNM anticipates that the remaining 5 MW of solar PV will be in service by December 31, 2011. PNM anticipates requesting recovery of these costs from customers through a rate rider. See 2010 Electric Rate Case below.

On July 1, 2010, PNM filed its renewable energy procurement plan for 2011. The 2011 plan proposed the procurement of 250,000 MWh of RECs from another New Mexico public utility for compliance with the renewable portfolio standard in 2011. On October 5, 2010, the NMPRC issued an order rejecting PNM's plan for 2011 as incomplete because certain planning assumptions used in the plan were found to be outdated, and ordered PNM to file a new plan within 60 days. On December 6, 2010, PNM filed a revised 2011 plan that proposed procurement of 423,860 MWh of wind generated RECs, but not the associated energy, from various bidders selected through a RFP process at a total cost of up to $5.5 million. The RECs would be retired for RPS compliance for 2011. The plan, as amended, requested a variance from the diversity requirements for solar and certain “other resources” for 2011 based on the RCT and availability constraints. A public hearing on the plan was held in April 2011. On June 2, 2011, the NMPRC issued an order that rejected PNM's proposal to procure wind RECs and directed PNM to use its best efforts to procure wind energy and associated RECs for 2011 compliance. The NMPRC granted PNM a variance from the resource diversity requirement conditioned upon PNM including in its 2012 procurement plan a proposal that would meet the diversity requirements by April 5, 2013. On July 1, 2011, PNM filed a motion for rehearing based on the NMPRC's disapproval of the use of RECs to meet the RPS requirements, the requirement that PNM meet the diversity requirements without explicit recognition of potential RCT constraints, the failure of the final order to adopt language concerning the relationship of the billing system modifications to the third party provider amendments to the Public Utility Act, and other matters. The NMPRC staff and NMIEC also filed motions for rehearing on the issue of the use of RECs for RPS compliance. On September 1, 2011, the NMPRC affirmed its order concerning cost recovery of the billing system modifications and its disapproval of the proposed REC purchase, and confirmed that the resource diversity requirements were subject to the reasonable cost threshold. On September 14, 2011, PNM filed a motion for expedited clarification of the order or in the alternative for approval of the procurement of additional wind resources. On October 3, 2011, NMIEC filed an appeal of the NMPRC's orders in the New Mexico Supreme Court. On October 11, 2011, the NMPRC denied PNM's request for clarification of the order and directed PNM to proceed with the procurement described in its request through the remainder of 2011 unless the NMPRC staff filed in opposition by October 20, 2011. On October 14, 2011, PNM filed a motion for stay of the NMPRC's orders, which the NMPRC denied on October 20, 2011. A stay motion by NMIEC is still pending. On October 17, 2011, the NMPRC staff filed an objection to the procurement and requested that the NMPRC issue an order finding that the procurement was not in the public interest. On October 27, 2011, the NMPRC issued an order rejecting the NMPRC staff's objection and directing PNM to procure the wind energy identified in its September 14, 2011 request. On October 28, 2011, PNM filed a motion in the New Mexico Supreme Court to become a party to the appeal previously filed by NMIEC. PNM cannot predict the outcome of this matter.

On July 1, 2011, PNM filed its Renewable Energy Portfolio Procurement Plan for 2012. The plan requests a variance from the RPS due to RCT limitations and also requests a variance from the RCT to allow PNM to continue to procure RECs from retail customers under PNM's Solar REC Incentive Program and to procure a small number of RECs from a hydroelectric resource to be developed by the City of Santa Fe. The plan is diversity compliant based on the reduced RPS, except for non-wind/non-solar resources, which are not currently available. In addition to the proposed procurements and requested variances, the plan describes

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

two other portfolios: one that would be fully compliant with the RPS and a second that would comply with both the full RPS and the diversity requirements for wind, solar, and distributed generation. Each of these portfolios is more costly than PNM's proposed portfolio and the plan did not request approval of them since they would exceed the RCT. Several intervenors and the NMPRC staff filed testimony in opposition to the manner in which PNM calculated the effect of the RCT and to other portions of the plan. A hearing was held in October 2011. PNM cannot predict the outcome of this matter.

NMPRC Rulemaking on Disincentives/Incentives to Energy Efficiency Programs

The NMPRC approved amendments to its energy efficiency rule on April 8, 2010 to be effective May 3, 2010. The amended rule allowed utilities to collect rate adders of $0.01 per KWh for lifetime energy savings and $10 per kilowatt for demand savings related to energy efficiency (collectively, the "interim adder") and demand response programs beginning in 2010. The amended rule also required investor-owned electric utilities to make filings by July 1, 2010 that proposed rate design and ratemaking measures to remove regulatory disincentives or barriers to achieve energy efficiency savings. PNM included its proposals in the 2010 Electric Rate Case described below. In the approved stipulation in the 2010 Electric Rate Case, PNM agreed that any such disincentives would be deemed addressed under the new rates allowed under the stipulation. Under the amended rule, after such measures became effective, the rate adder for energy saving was reduced to $0.005 per KWh (collectively, the "reduced adder"). The NMAG and NMIEC appealed the NMPRC order adopting the amended rule to the New Mexico Supreme Court, which issued an opinion on July 27, 2011 that annulled and vacated the NMPRC's order adopting the amended rule and remanded the matter to the NMPRC. PNM cannot predict the ultimate outcome of this matter.

On May 5, 2010, PNM filed proposed tariffs under the amended rule to recover a disincentive/incentive adder related to 2010 efficiency programs. PNM proposed to recover $6.2 million over a twelve-month period following NMPRC approval. The staff of the NMPRC filed testimony recommending the recovery of not more than $4.2 million. Following a hearing, the NMPRC issued an order authorizing recovery of $4.2 million over 12 months. PNM implemented a rate rider to recover the $4.2 million adder on December 29, 2010. The final order on the PNM 2010 Energy Efficiency Application described below extended the recovery period from 12 months to 18 months. As a result of the Supreme Court decision issued on July 27, 2011 PNM filed revised tariffs and ceased collecting this adder on August 21, 2011. Of the $4.2 million authorized for recovery, approximately $2.6 million had been collected through August 20, 2011. A NMPRC order on August 16, 2011 initiated an investigation to determine whether PNM should be required to refund any adder revenues that had been collected under the amended rule. The Hearing Examiner in the case arising from the reconciliation of 2010 program costs (see 2010 Energy Efficiency Application below) recommended that PNM not be required to refund any of the $2.6 million of 2010 adder revenue that had been collected as of August 21, 2011. The NMPRC issued an order on November 1, 2011 that generally approved the Hearing Examiner's recommended decision that PNM not be required to refund any of the interim adder revenue collected as of August 20, 2011, but left open the possibility that it may order a refund of interim adder revenue related to any disallowed program costs. On November 3, 2011, the NMPRC issued an order that allows for continuation of collection of reduced adder revenues. PNM cannot predict the outcome of this matter.

2010 Energy Efficiency Application

On September 15, 2010, PNM filed an energy efficiency program application for programs to be offered beginning July 1, 2011. PNM requested revisions to existing programs, revisions of estimates of participation and expenditure levels, approval of revised program cost recovery tariff riders, and approval of disincentive/incentive adders for 2011 energy efficiency and demand response programs. The total amount that PNM proposed to recover through the tariff riders was $32.9 million, which included the 2010 disincentive/incentive adder discussed above. Based on testimony filed by other parties, PNM accepted certain modifications to the plan, which resulted in a revised proposed recovery amount of $31.4 million. Following a hearing, the NMPRC issued a final order on June 23, 2011 that rejected the proposed plan modifications and ordered modifications to some programs in the original plan. The final order also adopted a recommendation by the NMPRC staff that the incentive adder rates of $0.005 per kWh and $10 per KW proposed by PNM be reduced to $0.002 per kWh and $4 per kW. The final order deferred consideration of certain issues relating to the recovery of past program costs, including whether PNM's demand response programs comply with statutory requirements, to a separate proceeding on PNM's 2010 Annual Electric Energy Efficiency Report. The final order approved a rider recovery amount of $22.8 million, including $17.1 million in program costs, $3.8 million for 2011 disincentive/incentive adders, and $1.9 million for 2010 disincentive/inventive adders that were not collected as of July 27, 2011, the effective date for the new rider rate approved by the NMPRC. The new rider rate of 3.018% was effective with bills rendered July 27, 2011. PNM filed a new rider effective August 21, 2011 that incorporated the higher rates approved in the 2010 Electric Rate case and

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

eliminated recovery of the remaining 2010 disincentive/incentive adder revenues of $1.6 million and the 2011 disincentive adder revenue of $2.5 million consistent with the Supreme Court decision in the appeal of the disincentive rulemaking discussed above. The new rider rate is 2.262%.

On April 1, 2011, PNM filed a reconciliation of energy efficiency program costs and collections as of December 31, 2010. Included in this filing was an adjustment of the adder amount to reflect the measured and verified savings for 2010 program participation in its 2010 Annual Electric Energy Efficiency Report, also filed April 1, 2011. PNM proposed an adjustment to the energy efficiency rider to recover an under-collected balance of $2.6 million. The new energy efficiency rider rate, adjusted for the under collected program costs and adjusted savings, would be increased from 2.441% to 2.839%. After suspending the proposed adjusted rates the NMPRC concluded that some of the program costs exceeded approved budgets and determined that an evidentiary hearing should be held to consider whether PNM should be permitted to recover over-budget program costs and certain adder amounts and whether sanctions should be imposed on PNM. In June 2011, PNM and the NMPRC staff reached an agreement on issues raised by the reconciliation filing and the suspension order under which PNM would be permitted recovery of substantially all of its program costs and would not be subject to any sanctions. PNM and the NMPRC staff filed testimony supporting the agreement. No party filed testimony in opposition. In a hearing held in July 2011, the Hearing Examiner questioned the reconciliation of 2009 Energy Efficiency Plan costs and identified costs of approximately $1.4 million, which may have exceeded NMPRC-approved budgets by more than 25% and for which NMPRC approval should have been obtained. The Hearing Examiner issued a recommended decision on October 3, 2011 that PNM should make permanent its suspension of the 2010 disincentive/incentive adder and that recovery of under-collected past program costs should be reduced to $2.4 million to account for the $0.3 million by which PNM's spending for its residential load management program exceeded 125% of the approved budget for program year 2009. PNM and another party filed exceptions to the recommended decision disallowing the $0.3 million and to other recommendations on October 13, 2011. The NMPRC issued a final order on November 1, 2011 that approved recovery of substantially all of the under-collected program costs through December 31, 2010, provided that PNM makes a compliance filing demonstrating the cost-effectiveness of one of the programs.

Investigation on Establishing a Policy Linking Utility Earnings to Quality of Customer Service

On May 28, 2009, the NMPRC ordered an investigation to consider the development of a service quality incentive mechanism for utilities in New Mexico, including PNM. The parties were to look at quality of service mechanisms established in other NMPRC orders, as well as the mechanisms that have been implemented in other states. Following a workshop process, the Hearing Examiner filed a report concluding that present circumstances do not warrant the implementation of a performance based ratemaking mechanism to either reward or penalize utilities for quality of service. Instead, the report recommended that utilities be required to file certain customer service reports annually for a three-year period commencing in 2011. The NMPRC issued an order on March 24, 2011 requiring utilities to file annually reports as recommended in the Hearing Examiner's report. These reports are to be filed annually by June 30 of 2011, 2012, and 2013. PNM made its first annual compliance filing on June 24, 2011.

Rates for Former TNMP Customers in New Mexico

PNM serves the former New Mexico customers of TNMP (“TNMP-NM” or “PNM South”) under rates approved by the NMPRC in its order approving PNMR's acquisition of TNMP. Under that order, rates charged to TNMP-NM customers were set through December 31, 2010. In January 2009, the NMPRC directed PNM to estimate the revenue requirement increase that would be reflected in a TNMP-NM rate application for rates effective January 2011. PNM estimated that the rate increase could be between 40% and 56% depending on fuel costs. In April 2009, the NMPRC directed PNM, the NMPRC staff, and other parties to attempt to reach consensus on ways to mitigate the impact of this potential rate increase and appointed a mediator. Mediation did not result in an agreement. On May 25, 2010, the NMPRC issued an order directing PNM and the NMPRC staff to file testimony addressing certain matters related to cost allocation. A hearing was held in December 2010. In April 2011, the NMPRC issued an order that consolidated this case with the pending 2010 Electric Rate Case discussed below. The NMPRC's order in the 2010 Electric Rate Case discussed below allows PNM to serve former TNMP customers in New Mexico under the same tariffs, including the FPPAC, that are applicable to all of PNM's other retail customers in New Mexico.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2010 Electric Rate Case

PNM filed its 2010 Electric Rate Case application with the NMPRC on June 1, 2010 for rate increases for all PNM retail customers to be effective April 1, 2011. The application proposed separate rate increases for those customers served by PNM (“PNM North”) prior to its acquisition of TNMP and for the customers formerly served by TNMP (“PNM South”). The proposed total increase of $165.2 million represented a 22% increase for PNM North and a 20% increase for PNM South. The filed revenue requirements were based on a future test period ending December 31, 2011. PNM proposed to implement the increase in two phases. Phase 1 would have become effective April 1, 2011 (PNM North: $111.1 million, 16%; PNM South: $8.7 million, 14%), and Phase 2 would have become effective January 1, 2012 (PNM North: $41.7 million, 6%; PNM South: $3.6 million, 6%). PNM also proposed to implement a FPPAC for PNM South. This was the first rate case filing in New Mexico proposing a future test year consistent with recent amendments to the Public Utility Act. The NMPRC initially suspended the rates until April 1, 2011, which date was later extended.

In October 2010, PNM began meeting with the NMPRC staff and other parties to discuss settlement. On February 3, 2011, PNM, NMPRC staff, NMAG, NMIEC, ABCWUA, Buckman Direct Diversion Board, and the City of Alamogordo, New Mexico entered into a stipulation that, if approved by the NMPRC, would have resolved all issues in the 2010 Electric Rate Case and provided a rate path for PNM through December 31, 2013. Other parties filed statements opposing the stipulation. This stipulation, which reflected some aspects of a future test year, was subject to approval of the NMPRC. The stipulation would have allowed PNM to increase rates by $45.0 million immediately following approval and by an additional $40.0 million beginning January 1, 2012. The proposed rates were designed so that PNM North customers and PNM South customers would have the same percentage increase. The PNM South customers would also be covered by the same FPPAC that is utilized for the PNM North customers. In addition, subject to further NMPRC approvals, PNM would be able to recover the costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning July 1, 2012 or twelve months after the effective date of the new electric rates and would also be able to implement a separate rate rider in 2013 to recover up to an additional $20.0 million to cover changes in plant-related rate base between June 30, 2010 and December 31, 2012. PNM's next general rate adjustment could not go into effect before January 1, 2014, except that PNM could file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010. In addition, the stipulation would limit the amount that could be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs during the period covered by the stipulation. Recovery of costs in excess of the limits would be deferred for collection, without carrying costs, to future periods. If the stipulation was approved, PNM would forego collection of $10.0 million of the under-collected amount in the FPPAC balancing account as a regulatory disallowance. On March 17, 2011, PNM filed a request for interim rates to go into effect on May 15, 2011, which was denied by the NMPRC. A public hearing on the stipulation was held in May 2011. The hearing examiner issued a Certification of the Stipulation on June 21, 2011. The Hearing Examiner recommended approval of most of the terms of the stipulation, including the $85.0 million rate increase, the implementation of the increase in two phases, the moratorium on rate changes through December 31, 2013 the application of PNM North rate schedules to all New Mexico customers, and approval of a consolidated fuel clause. The Hearing Examiner, however, recommended disapproval of the capital additions rider and the proposed residential rate design. PNM and other parties filed exceptions to the Certification of the Stipulation. On August 8, 2011, the NMPRC issued a final order that provides for a $72.1 million rate increase, rejects the capital additions rider, changes the residential rate design, and adopts, approves, and accepts the stipulation with other modifications. PNM and other parties to the stipulation filed an amended stipulation on August 11, 2011 that conforms to the modifications contained in the NMPRC's August 8, 2011 order. No party requested rehearing of the order. The amended stipulation allows PNM to file a new rate case for rates to be effective July 1, 2013. PNM implemented the new rates on August 21, 2011.

As a result of the above, PNM recorded a pre-tax loss for the $10.0 million of fuel costs discussed above that will not be recovered through the FPPAC. In addition, PNM recorded a pre-tax loss aggregating $7.5 million for costs that will not be recovered in rates approved by the NMPRC order. These costs primarily relate to rate case expenses for the 2010 Electric Rate Case, expenses related to an audit of fuel and purchased power costs, loss on debt re-acquired in previous years, and the 2010 settlement of claims against DOE related to spent nuclear fuel at PVNGS. These amounts were recorded as of June 30, 2011 and are reflected as regulatory disallowances on PNM's Condensed Consolidated Statement of Earnings.

2011 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 must contain an action plan covering the first four years of that period. In its most recent IRP, which was filed

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

on July 18, 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. However, PNM has not entered into any commitments regarding these plans beyond what is otherwise described herein. 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 in the event that at least two parties request mediation. PNM is unable to predict the outcome of this matter.

Transmission Rate Case

On October 27, 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually and revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms.  If approved, the rate increase would apply to all of PNM's wholesale electric transmission service customers, which include other utilities, electric co-operatives, and entities that use PNM's transmission system to transmit power at the wholesale level.  The proposed rate increase would not impact PNM's retail customers. On December 29, 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. PNM and other parties to the case have engaged in settlement discussions and will continue the negotiation process under the settlement judge procedures, but due to an impasse in regards to settlement negotiations, the settlement judge issued an order in August 2011 designating an ALJ, establishing procedural time standards, and terminating settlement judge procedures. The hearing for this proceeding is scheduled to commence on April 4, 2012. PNM is unable to predict the outcome of this proceeding.

Firm Requirements Rate Case

On September 15, 2011, PNM filed an amended sales agreement between PNM and Navopache Electric Cooperative, Inc. (“NEC”) with FERC. The agreement proposes a cost of service based rate for the partial requirements electric service and ancillary services PNM provides to NEC, which would result in an annual increase of $8.7 million (39.8%) over rates PNM currently charges NEC. PNM also proposes a FPPAC and full recovery of certain third-party transmission charges PNM incurs to serve NEC. The proposed effective date is November 14, 2011. NEC has filed a protest to PNM's filing with FERC. PNM is unable to predict the outcome of this proceeding.

TNMP

TNMP Competitive Transition Charge True-Up Proceeding

The purpose of the true-up proceeding was to quantify and reconcile the amount of stranded costs that TNMP may recover, as a CTC, from its transmission and distribution customers. A 2004 PUCT decision established $87.3 million as TNMP's stranded costs. TNMP and other parties made a series of appeals on the ruling. On June 24, 2011, the Texas Supreme Court denied all petitions for review pending in the case. The decision rejects the argument that TNMP's stranded cost balance should be zero. It also denied TNMP's request to remand the case in order to present further evidence of stranded costs that the PUCT previously refused to consider. TNMP filed a motion for rehearing on July 11, 2011 requesting the Texas Supreme Court to reconsider its decision on TNMP's request to present additional stranded costs. No other party filed a motion for rehearing. The Texas Supreme Court denied the motion for rehearing on August 12, 2011 concluding this matter.

Interest Rate Compliance Tariff

Following a revision of the interest rate on TNMP's CTC, TNMP filed a compliance tariff to implement the new 8.31% rate. TNMP's filing proposed to put the new rates into effect on February 1, 2008. Intervenors asserted objections to the compliance filing. PUCT staff urged that the PUCT make the new rate effective as of December 27, 2007 when the PUCT's order establishing the correct rate became final. After regulatory proceedings, the PUCT issued an order making the new rate retroactive to July 20, 2006. TNMP filed an appeal of this order in the District Court in Austin, Texas. A hearing was held on June 17, 2010. On June 28, 2010, the District Court reversed the PUCT decision and remanded the matter back to the PUCT for a determination that is not retroactive. The PUCT and other parties appealed the decision to the Texas 3^rd Court of Appeals and presented oral argument on March 23, 2011. On May 12, 2011, the 3^rd Court of Appeals issued its opinion reversing the District Court and reaffirming the PUCT's decision. TNMP filed its petition for review with the Texas Supreme Court on July 29, 2011. Responses from opposing parties are to be filed by November 9, 2011. TNMP is unable to predict if the Texas Supreme Court will review the decision or

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

the ultimate outcome of this matter. However, due to the new retroactive ratemaking theory contained in the Texas 3^rd Court of Appeals opinion, TNMP recorded a regulatory disallowance of $3.9 million, before income taxes, in the three months ended June 30, 2011 to reflect the impact of applying the 8.31% rate retroactively.

Advanced Meter System Deployment and Surcharge Request

On May 26, 2010, TNMP filed a request with the PUCT to approve TNMP's proposed advanced meter deployment. The filing also requested a surcharge to collect $157.9 million in costs over 12 years, including recovery of capital expenditures of $70.6 million. Due to changes in the tax law, TNMP filed supplemental testimony on February 16, 2011 to reflect the effects of the bonus depreciation, a new WACC, and other changes. The filing amended the requested surcharge to collect $126.1 million, including capital expenditures of $70.2 million incurred through 2015. On May 18, 2011, the parties announced a settlement that permits TNMP to collect the costs of a $113.3 million advanced meter deployment. The settlement approves a lower cost deployment due principally to the removal of an outage management system from TNMP's proposal. The settlement was approved by the PUCT on July 8, 2011. TNMP began collecting the surcharge on August 11, 2011 in order to collect a total of $113.3 million in costs over 12 years. Deployment of advanced meters began in September 2011.

2010 Rate Case

On August 26, 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues, requesting that new rates go into effect on October 1, 2010. In its request, TNMP also asked for permission to update its catastrophe reserve fund that would be utilized to pay for a utility system's costs in recovering from natural disasters and acts of terrorism. Additionally, TNMP requested a rate rider to recover costs to storm harden its system. On November 8, 2010, the presiding ALJ severed the rate case expense issues into a separate proceeding. In December 2010, the parties announced to the ALJ that a settlement had been reached in the case and a stipulation supporting the settlement was filed. The settlement provided for a revenue requirement increase of $10.25 million, a return on equity of 10.125%, and a hypothetical 55%/45% debt-equity capital structure. The PUCT approved the settlement on January 27, 2011. TNMP implemented the new rates on February 1, 2011.

2010 Rate Case Expense Proceeding

The determination of the amount of reasonable rate case expenses incurred by TNMP and other parties in TNMP's 2010 Rate Case was severed into a separate proceeding. On January 26, 2011, the ALJ set a procedural schedule requiring the parties who participated in the 2010 rate case to file testimony supporting their respective incurred expenses. The parties agreed to a settlement of the case, which was approved by the PUCT on May 26, 2011. TNMP began collecting $2.8 million over three years on July 1, 2011.

Remand of ERCOT Transmission Rates for 1999 and 2000

Following a variety of appeals, the ERCOT transmission rates approved in 1999 and 2000 were recently remanded back to the PUCT.  The issues relevant to TNMP are addressed in three separate dockets, but those proceedings are expected to be heard jointly.  These dockets concern the recalculation of rates for the fourth quarter of 1999 and all of 2000 to correct over-payments made by certain market participants and the recovery of additional, undetermined transmission costs by City Public Service Board of San Antonio ("CPS"). On October 5, 2011, TNMP joined in a non-unanimous settlement of the issues relating to resettlement of the last four months of 1999. CPS is the sole opposing party. The settlement would resolve all issues except CPS's claim that it can file a transmission rate case in 2011 to determine its actual rates for the fourth quarter of 1999 and all of 2000. As that claim is pending in a separate docket, the settlement does not prejudice CPS' right to pursue the claim in the pending proceeding. TNMP would receive $1.6 million under the settlement, if approved. However, whether such funds would have to be passed on to customers would be determined in TNMP's next transmission cost recovery factor filing. TNMP cannot predict the ultimate outcome of this matter.

Energy Efficiency

On April 29, 2011, TNMP filed an application for approval of its 2012 energy efficiency programs and requested recovery through an energy efficiency cost recovery factor. TNMP estimates the costs of its 2012 energy efficiency programs to be $4.4 million and requests to collect this amount based on a per customer charge over 12 months. Additionally, as permitted by the

67

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PUCT rules, TNMP's request includes a bonus collection amount of $0.3 million due to the fact that its 2010 energy efficiency programs exceeded the performance goals set by the PUCT. On June 23, 2011, the PUCT issued a supplemental preliminary order clarifying that certain costs totaling $0.4 million that, due to a PUCT rule change, TNMP expects to incur during its current 2011 program should be considered in its energy efficiency 2012 filing and not in the current proceeding. On August 2, 2011, TNMP and the other parties announced a settlement of the material issues in this matter. The settlement allows TNMP to collect the $0.3 million bonus for 2010 and estimated 2012 program costs of $3.4 million and sets, for good cause, TNMP's 2012 demand savings goal at 4.8 MW instead of the 5.9 MW goal that would otherwise apply. The settlement does not alter the current PUCT energy efficiency rules permitting recovery of any under-collection that might exist after the 2012 program year. TNMP received a final order on September 13, 2011 that approved the settlement in whole, except a minor amount for under-recovery of administrative costs from the 2010 energy efficiency expenses. TNMP's new rates will be effective January 1, 2012.

Periodic Rate Adjustment

On May 28, 2011, the Governor of Texas signed Senate Bill 1693, which will allow for an annual periodic rate adjustment to reflect changes in investments in distribution assets. To implement the new statute, the PUCT opened a rule-making proceeding. A proposed rule was published by the PUCT in the Texas Register on July 22, 2011. Comments to the new rule were filed in August 2011. A public hearing was held on August 15, 2011. The PUCT approved a new rule on September 27, 2011. The rule allows ERCOT distribution utilities to only file for a periodic rate adjustment during the period April 1 through April 8 of each year and requires the PUCT to deny an electric utility's application for a periodic rate adjustment if the electric utility is earning more than its authorized rate of return using weather-normalized data.

(11) Optim Energy

Information concerning Optim Energy is discussed in Note 22 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. In January 2007, Optim Energy was created by PNMR and ECJV, a wholly owned subsidiary of Cascade, to serve expanding U.S. markets, principally the areas of Texas covered by ERCOT. PNMR and ECJV each had a 50 percent ownership interest in Optim Energy, a limited liability company.

Impairment and Restructuring

Beginning in 2009 and continuing throughout 2010, Optim Energy was affected by adverse market conditions, primarily low natural gas and power prices. In addition to these adverse market conditions, reported sales of electric generating resources within the ERCOT market area were transacted at prices (per KW of generating capacity) that were substantially below the amounts recorded for the electric generating plants underlying PNMR’s investment in Optim Energy. Under GAAP, these factors were indicators of impairment that required an impairment analysis to be performed by PNMR of its investment in Optim Energy as of December 31, 2010. PNMR’s analysis indicated that its entire investment in Optim Energy was impaired and PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31, 2010, resulting in a pre-tax impairment loss of $188.2 million. In accordance with GAAP, PNMR has not recorded losses associated with its investment in Optim Energy in 2011 as PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources.

As a result of the adverse market conditions described above, PNMR (in collaboration with Optim Energy and ECJV) assessed various strategic alternatives relating to Optim Energy. On September 23, 2011, PNMR, ECJV, and Cascade agreed to restructure Optim Energy and ECJV made an equity contribution to Optim Energy in exchange for an increased ownership interest, which resulted in PNMR's ownership in Optim Energy being reduced from 50% to 1%. Optim Energy's debt is non-recourse to PNMR. As part of this transaction, PNMR did not make any equity contribution to Optim Energy nor will it be required to make any contribution in the future. From January 1, 2012 through December 31, 2013, ECJV has the option to purchase PNMR's 1% ownership interest in Optim Energy at fair market value and, if that option is not exercised, PNMR would have the option from June 30, 2014 to December 31, 2015 to sell its 1% ownership interest in Optim Energy to ECJV at fair market value. PNMR accounted for its investment in Optim Energy using the equity method of accounting until September 23, 2011 and is using the cost method thereafter. The fair value of PNMR's 1% ownership interest in Optim Energy was de minimis at September 30, 2011. PNMR Services Company has been providing certain corporate services to Optim Energy and will continue to provide certain services at least through the end of 2011 and after that with respect to certain tax matters.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Operational Information

As discussed above, PNMR fully impaired its investment in Optim Energy at December 31, 2010 and has not recognized losses of Optim Energy from January 1, 2011 through September 23, 2011 when PNMR ceased to account for its investment using the equity method of accounting. Accordingly, Optim Energy has no impact on PNMR's 2011 balance sheet, statement of earnings, and statement of cash flows. Therefore, summarized financial information for Optim Energy is not presented.

Optim Energy had net earnings (loss) of $7.6 million and $(6.8) million in the three months and nine months ended September 30, 2010. PNMR recognized net earnings (loss) from Optim Energy of $2.5 million and $(5.7) million in the three months and nine months ended September 30, 2010. Such amounts include amortization of a basis difference between PNMR's recorded investment in Optim Energy and 50 percent of Optim Energy’s equity.

(12) Related Party Transactions

PNMR, PNM, TNMP, and, through September 23, 2011, Optim Energy are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR, its subsidiaries, and Optim Energy in accordance with shared services agreements. There was also a services agreement for Optim Energy to provide services to PNMR. Additional information concerning the Company’s related party transactions is contained in Note 20 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

See Note 11 for information concerning Optim Energy. 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,
	2011		2010		2011		2010
	(In thousands)
Electricity, transmission and distribution related services billings:
TNMP to PNMR	$	12,196	$	11,495	$	30,608	$	30,717
Services billings:
PNMR to PNM	24,680		26,373		70,849		69,948
PNMR to TNMP	7,295		6,798		21,250		19,090
PNM to TNMP	40		100		327		379
TNMP to PNMR	48		53		145		266
PNMR to Optim Energy	1,277		1,393		4,083		4,304
Optim Energy to PNMR	4		107		23		157
Income tax sharing payments:
PNMR to PNM	—		—		—		35,190
Interest charges:
TNMP to PNMR	8		57		36		242
PNM to PNMR	9		—		45		—
PNMR to PNM	33		—		97		—

(13) Jointly-Owned Electric Generating Plants

Information concerning Jointly-Owned Electric Generating Plants is discussed in Note 14 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. As discussed in that note, operation of each of the three PVNGS units requires an operating license from the NRC and a portion of PNM’s interests in PVNGS Units 1 and 2 are held under leases that expire in 2015 and 2016. The NRC issued 40 year operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. In December 2008, APS, on behalf of the PVNGS participants, applied for renewed operating licenses for the PVNGS units for a period of 20 years beyond the expirations of the current licenses. On April 21, 2011, the NRC approved extensions in the operating licenses for the plants for 20 years through 2045 for Unit 1, 2046 for Unit 2, and 2047 for Unit 3.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Information concerning the Company's AROs is contained in Note 15 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. PNM has an ARO for PVNGS that includes the obligation for nuclear decommissioning of that facility. In the second quarter of 2011, PNM adopted a new decommissioning study for PVNGS that reflects updated cash flow estimates and the 20-year license extension, which extends the commencement of decommissioning to 2045. The new study resulted in a $4.2 million decrease to the ARO liability for asset retirements and electric plant in service.

The Four Corners plant site is leased from the Navajo Nation and is also subject to a rights-of-way grant from the federal government. APS, on behalf of the Four Corners participants, negotiated amendments to the facility lease with the Navajo Nation, which would extend the Four Corners leasehold interest to 2041. The amendments have been approved by the Navajo Nation Council and signed by the Nation’s President. The effectiveness of the amendments also requires the approval of the DOI, as does the related federal rights-of-way grant, which the Four Corners participants will pursue. A federal environmental review will be conducted as part of the DOI review process.PNM’s share of the annual lease payments will be $0.9 million beginning in 2016.

(14) New Accounting Pronouncements

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

Accounting Standards Update 2011-04 - Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs

The Financial Accounting Standards Board ("FASB") released amended guidance to provide a consistent definition of fair value and to ensure fair value measurement and disclosure requirements are similar between U.S. GAAP and International Financial Reporting Standards.  The update changes certain fair value measurement principles, further enhances disclosure requirements related to transfers between hierarchy levels, and increases qualitative disclosures regarding unobservable inputs used in Level 3 measurements, including the sensitivity of recurring Level 3 measurements to changes in significant unobservable inputs. In addition, the update requires disclosure of the level within the fair value hierarchy for fair value disclosures of instruments recorded on an amortized cost basis. The update is required to be applied prospectively and is effective for interim and annual reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The Company does not believe this guidance will have a material impact on the Company's financial statements and will comply with this requirement upon its effective date.

Accounting Standards Update 2011-05 - Comprehensive Income: Presentation of Comprehensive Income

The FASB released amended guidance regarding presentation of comprehensive income in financial statements. The update requires entities to report comprehensive income in either one continuous statement of comprehensive income or in two separate but consecutive statements. Under the two-statement approach, the first statement would include components of net income consistent with current guidance, and the second statement would include components of other comprehensive income. The update is effective for interim and annual reporting periods beginning after December 15, 2011, with early adoption permitted. The Company does not believe this guidance will have a material impact on the Company's financial statements and will comply with this requirement no later than its effective date.

Accounting Standards Update 2011-08 - Intangibles-Goodwill and Other: Testing Goodwill for Impairment

The FASB released amended guidance that is intended to simplify requirements to test goodwill for impairment. Under the amended guidance, an entity will have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less that its carrying amount. If an entity determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the two-step impairment test will not be necessary. However, if an entity is unable to make this conclusion, then it will be required to perform the first step of the two-step impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit, as required by current guidance. The update is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. The Company is currently evaluating the impacts of this new standard.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(15) Goodwill and Other Intangible Assets

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. Additionally, the trade name “First Choice” and the First Choice customer list were acquired in the TNP acquisition. The trade name was considered to have an indefinite useful life; therefore, no amortization was recorded. The useful life of the customer list was estimated to be approximately eight years.

The Company evaluates its goodwill and non-amortizing intangible assets for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill or intangible assets may be impaired. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit. A discounted cash flow methodology is primarily used to estimate the fair value of each 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 for each reporting unit.

For non-amortizing intangibles other than goodwill, the Company compares the fair value of the intangible asset to its recorded value. For goodwill, the first step of the impairment test requires that the Company compare the fair value of each reporting unit with its carrying value, including goodwill. If as a result of this analysis, the Company concludes there is an indication of impairment in a reporting unit having goodwill, the Company 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 Company 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.

The annual evaluations performed as of April 1, 2011 and 2010 did not indicate impairments of the goodwill or other intangible assets of any of the Company’s reporting units. Since the annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill, other intangible assets, and impairments is contained in Note 25 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

(16) Sale of First Choice

PNMR has previously reported that it was evaluating strategic alternatives with respect to 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 actual amounts of certain components of working capital at closing, pursuant to a Stock Purchase Agreement dated September 23, 2011. Closing of the transaction was subject to customary conditions, including an antitrust review under the Hart-Scott-Rodino Antitrust Improvements Act, which was received on October 7, 2011. Closing occurred on November 1, 2011, with PNMR receiving $329.3 million, which includes an estimate of the components of working capital discussed above. For accounting purposes, the sale was effective as of the close of business on October 31, 2011. Such amount is subject to adjustment based on the actual amounts of the components of working capital at October 31, 2011. PNMR expects to use the net proceeds from the sale of First Choice to repurchase, depending on market conditions, certain of PNMR's outstanding debt and equity (see Note 7) and for other corporate purposes, including repayment of borrowings under the PNMR Revolving Credit Facility. PNMR Services Company will continue to provide certain services at cost to First Choice for a transitional period of up to nine months following closing.

First Choice is reflected as being "held-for-sale" in PNMR's September 30, 2011 Condensed Consolidated Balance Sheet. Because PNMR will continue to have direct cash flows resulting from transmission and distribution services provided by TNMP to First Choice, First Choice is not reflected as discontinued operations. A summary of the major assets and liabilities reflected

71

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

as "held-for-sale" in PNMR's September 30, 2011 Condensed Consolidated Balance Sheet. The amounts included in the December 31, 2010 Condensed Consolidated Balance Sheet are also presented for comparative purposes although such amounts are not presented separately on the Condensed Consolidated Balance Sheet.

	September 30,		December 31,
	2011		2010
	(In thousands)
Current assets of business unit held for sale
Cash and cash equivalents	$	3,462	$	3,888
Accounts receivable, net of allowance for uncollectible accounts of $11,009 and $9,694	49,749		25,719
Unbilled revenues	38,527		26,666
Derivative instruments	28,452		14,556
Other current assets	45,929		44,408
	$	166,119	$	115,237
Non-current assets of business unit held for sale
Net property and equipment	$	7,345	$	6,986
Goodwill and other intangible assets, net	69,308		69,439
Derivative instruments	8,817		5,264
Other long-term assets	15,589		10,718
	$	101,059	$	92,407
Current liabilities of business unit held for sale
Accounts payable	$	40,757	$	28,157
Affiliate accounts payable	6,632		5,001
Derivative instruments	39,272		28,297
Other current liabilities	17,254		17,085
	$	103,915	$	78,540
Non-current liabilities of business unit held for sale
Derivative instruments	$	14,460	$	10,823
Other long-term liabilities	3,136		4,847
	$	17,596	$	15,670

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management's Discussion and Analysis of Financial Condition and Results of Operations for PNMR is presented on a combined basis, including certain information applicable to PNM and TNMP. The MD&A for PNM and TNMP is presented as permitted by Form 10-Q General Instruction H (2). For discussion purposes, 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

BUSINESS AND STRATEGY

PNMR provides electricity and energy efficiency products and services in core regulated and, until recently, unregulated markets to help customers meet and manage their energy needs. PNMR has previously reported that it was evaluating strategic alternatives with respect to its unregulated businesses, First Choice and Optim Energy. As discussed in Note 16, PNMR entered into an agreement for the sale of First Choice to Direct LP, Inc. on September 23, 2011. Closing occurred on November 1, 2011 with PNMR receiving $270.0 million plus $59.3 million for estimated working capital, which amount is subject to adjustment based on the actual amounts of certain components of working capital at October 31, 2011. PNMR expects to use the net proceeds from the sale of First Choice to repurchase, depending on market conditions, certain of PNMR's outstanding debt and equity and for other corporate purposes, including repayment of borrowings under the PNMR Revolving Credit Facility. As discussed in Note 11, PNMR, ECJV, and Cascade entered into agreements on September 23, 2011, whereby Optim Energy was restructured and ECJV made an equity contribution to Optim Energy in exchange for an increased ownership interest, which resulted in PNMR's ownership in Optim Energy being reduced from 50% to 1%. Optim Energy's debt is non-recourse to PNMR. ECJV has the option to purchase PNMR's 1% ownership interest in Optim Energy at fair market value beginning in 2012. By exiting from its unregulated businesses, PNMR is now focused on its regulated businesses in New Mexico and Texas.

Regulated Operations

PNM

Critical to PNMR’s success for the foreseeable future is the financial health of PNM, PNMR’s largest subsidiary, which is highly dependent on favorable regulatory treatment. PNM anticipates a trend toward increasing costs of providing electric service, including costs of renewable energy sources under the RPS established pursuant to the REA and related regulations of the NMPRC. PNM also anticipates increases in costs related to compliance with environmental regulations, rights-of-way, pension and benefits, and depreciation. Increases in these items were included in PNM's 2010 Electric Rate Case, the transmission rate case, and the firm requirements rate case described below to the extent applicable to those filings. PNM will continue to seek recovery of these increased costs of providing service to regulated customers through future rate filings. The impact that rate increases may have on customers’ usage and their ability to pay is unknown.

PNM filed its 2010 Electric Rate Case application with the NMPRC on June 1, 2010 for rate increases for all PNM retail customers to be effective April 1, 2011, including customers formerly served by TNMP (“PNM South”). The proposed total increase was $165.2 million. The filed revenue requirements were based on a future test period ending December 31, 2011. PNM also proposed to implement a FPPAC for PNM South. This was the first rate case filing in New Mexico proposing a future test year consistent with recent amendments to the Public Utility Act. On August 8, 2011, the NMPRC issued a final order modifying a stipulation reached by PNM and other parties. An amended stipulation was filed on August 11, 2011 that conforms to the modifications contained in the August 8, 2011 order. See Note 10. As modified, PNM is allowed a revenue increase for all New Mexico retail customers of $72.1 million annually that was implemented August 21, 2011. The PNM South customers are now covered by the same FPPAC that is utilized for other retail customers of PNM. In addition, subject to further NMPRC approvals, PNM would be able to recover the costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning August 21, 2012. PNM's next general rate adjustment could not go into effect before July 1, 2013, except that PNM could file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010. In addition, the amount that can be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs is limited, with recovery of costs in excess of the limits deferred for collection, without carrying costs, to future

73

periods. The stipulation, as approved, resulted in PNM recognizing pre-tax losses of $17.5 million for costs that will not be recovered from customers. These amounts were recorded as of June 30, 2011 and are reflected as regulatory disallowances on PNM's Condensed Consolidated Statement of Earnings.

On October 27, 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually.  If approved, the rate increase would apply 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 proposed rate increase would not impact PNM's retail customers. The proposed rates were implemented on June 1, 2011, subject to refund. Although settlement discussions have occurred and will continue, a hearing for this proceeding is scheduled to commence on April 4, 2012. PNM is unable to predict the outcome of this proceeding.

On September 15, 2011, PNM filed with FERC to increase rates for electric service and ancillary services PNM provides to Navopache Electric Cooperative, Inc., which would result in an annual increase of $8.7 million (39.8%) over current rates. PNM also proposes a FPPAC and full recovery of certain third-party transmission charges. The proposed effective date of the increase is November 14, 2011. The cooperative has filed a protest to PNM's filing with FERC. PNM is unable to predict the outcome of this proceeding.

TNMP

TNMP’s financial health is also highly dependent on continued favorable regulatory treatment. TNMP has the ability to update its transmission rates twice a year to reflect changes in its invested capital. Additionally, on September 27, 2011, the PUCT approved a rule, which allows for an annual periodic rate adjustment to reflect changes in invested distribution capital. On March 2, 2010, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base was $33.8 million, with a total revenue requirement increase of $5.5 million. The requested updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The PUCT approved the interim adjustment on May 14, 2010.

On August 26, 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues, requesting that new rates go into effect on October 1, 2010. In December 2010, the parties announced that a settlement had been reached in the case and a stipulation supporting the settlement was filed. The settlement provided for a revenue requirement increase of $10.25 million beginning February 1, 2011, an inferred return on equity of 10.125%, and a hypothetical 55%/45% debt-equity capital structure. The PUCT approved the settlement on January 27, 2011. TNMP implemented the new rates on February 1, 2011.

On July 8, 2011, the PUCT approved TNMP's proposal for advanced meter deployment. The final order permits TNMP to begin collection of a surcharge on August 11, 2011 in order to collect a total of $113.3 million in deployment costs over 12 years.

Competitive Businesses

First Choice

As a REP, First Choice operates in the highly competitive Texas retail market, which has experienced extreme price volatility and transmission congestion in the past. ERCOT controls the transmission of power in the areas that First Choice supplies. ERCOT historically has operated in a manner that resulted in congestion of the transmission system when large volumes of power were being transmitted between zones. Congestion tends to drive prices up in the spot market and negatively impacts margins realized from end use customers. Beginning in 2008, these conditions were exacerbated by weather and depressed economic conditions resulting in very high levels of customer turnover and levels of uncollectible accounts significantly higher than historical experience. Recently, ERCOT changed its operating protocols and the Texas retail market has been more stable. In addition, both power and natural gas prices decreased significantly, resulting in a substantial increase in margins realized by First Choice in 2009 and continuing to a lesser degree in 2010. These factors and the increased focus on growing commercial accounts, customer credit standards, and improved customer service contributed to an improvement in First Choice’s results of operations, including reductions in bad debt expense. As discussed above on November 1, 2011, PNMR completed the sale of First Choice.

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Optim Energy

PNMR’s 50% ownership of Optim Energy allowed it to participate in the operation of Optim Energy’s generating assets and business and the formulation of Optim Energy’s business strategy intending to capitalize on growth opportunities in one of the nation’s growing power markets. Optim Energy was affected by continuing adverse market conditions, primarily low natural gas and power prices beginning in 2009 continuing through 2010. In addition to these continuing adverse market conditions, reported sales of electric generating resources within the ERCOT market have been transacted at prices (per KW of generating capacity) that were substantially below the amounts recorded for electric generating plants underlying PNMR’s investment in Optim Energy. As of December 31, 2010, PNMR performed an impairment analysis in accordance with GAAP of its investment in Optim Energy, determined its entire investment was impaired, and reduced the carrying value of its investment to zero. See Note 11. In accordance with GAAP, PNMR has not recorded losses (or income) associated with its investment in Optim Energy in 2011 as PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources. As discussed above, PNMR entered into agreements on September 23, 2011 that reduced PNMR's ownership in Optim Energy from 50% to 1%.

Environmental Sustainability

The Company also undertakes environmental sustainability efforts. These efforts include environmental upgrades, improving energy efficiency, expanding the renewable energy portfolio of generation resources, and proactively addressing climate change. In early 2009, PNM completed environmental upgrades to each of the four units at SJGS. PNM’s share of the costs of these upgrades, which reduced the levels of NOx, SO₂, and mercury emissions, amounted to $161 million. As described in Note 10, PNM is subject to the RPS established by the REA and related regulations issued by the NMPRC, which require utilities to achieve certain levels of retail energy sales from renewable sources within its generation mix, including wind, solar, distributed generation, and other sources. PNM is actively engaged in activities to meet the NMPRC standard. PNM has also established various programs to promote energy efficiency, subject to the approval of the NMPRC. The Company monitors initiatives regarding legislation or regulation regarding climate change, including GHG, and participates in organizations and forums concerning climate change. The Company is supportive of a federal program that includes an economy-wide system of limitations on GHG that would include a cap and trade provision and a system of allowances and offsets designed to mitigate rate increases to utility customers. The Company is exploring various methods to mitigate its GHG in anticipation of climate change legislation or regulation, including increasing energy efficiency programs and increased reliance on renewable energy resources. See Climate Change Issues under Other Issues Facing the Company below for additional discussion of climate change matters. All of these efforts involve costs that the Company believes should be recoverable through rates charged to customers to the extent the costs are attributable to regulated operations. However, recovery of these costs is subject to the approval of regulators and will cause upward pressure on rates.

Economic Conditions

In the last half of 2008 and early 2009, global economic conditions deteriorated dramatically, encompassing the U.S. residential housing market, and global and domestic equity and credit markets, which resulted in reduced usage of electricity by the Company’s customers. Although New Mexico and Texas were not impacted as greatly as some other areas of the United States, with unemployment rates that are somewhat lower than the rest of the nation, the territories served by the Company’s electric businesses have been impacted by the recession and general economic downturn. The Company believes that electric sales volume will increase modestly in the immediate future.

The disruption in the credit markets in late 2008 and early 2009 had a significant adverse impact on numerous financial institutions, including several of the financial institutions that have dealings with the Company. The Company’s liquidity instruments have not been materially impacted by the credit environment and management does not expect that the Company will be materially impacted in the near future. In late 2008 and early 2009, there was also a significant decline in the level of prices of marketable equity securities, including those held in trusts maintained for future payments of benefits under the Company’s pension and retiree medical plans. Although the general price levels of marketable equity securities have recovered somewhat, the stock market decline could result in increased levels of funding and expense applicable to these trusts.

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RESULTS OF OPERATIONS

Executive Summary

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
	(In millions, except per share amounts)
Net earnings	$	43.7	$	48.6	$	(4.9	)	$	64.4	$	63.0	$	1.4
Average diluted common and common equivalent shares	91.7		91.8		(0.1		)	92.0		91.8		0.2
Net earnings per diluted share	$	0.48	$	0.53	$	(0.05	)	$	0.70	$	0.69	$	0.01

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

	Three Months Ended			Nine Months Ended
	September 30, 2011			September 30, 2011
	(In millions)
PNM Electric	$	(0.8	)	$	(11.7	)
TNMP Electric	1.6			4.0
First Choice	(3.0		)	8.0
Corporate and Other	(1.1		)	(2.3		)
Optim Energy	(1.5		)	3.4
Net change	$	(4.9	)	$	1.4

Detailed information regarding the changes in earnings is included in the segment information below. The after-tax changes for the three months and nine months ended September 30, 2011 relate primarily to rate increases at PNM and TNMP implemented in 2011 and the write off of regulatory disallowances of $10.6 million at PNM and $2.6 million at TNMP in the second quarter of 2011. In addition, mark-to-market gains on unrealized economic hedges at PNM increased earnings by $2.5 million and $6.8 million for the three months and nine months ended 2011 compared to 2010. At First Choice, mark-to-market gains on unrealized economic hedges increased earnings by $7.3 million and $22.7 million for the three months and nine months ended 2011 compared to 2010. PNMR fully impaired its investment in Optim Energy at December 31, 2010 and reduced the carrying value of that investment to zero. In accordance with GAAP, PNMR did not record losses associated with its investment in Optim Energy in 2011. In 2010, PNM recorded a $5.1 million gain for a settlement associated with the Republic Savings Bank litigation, which did not recur in 2011.

Segment Information

The following discussion is based on the segment methodology that PNMR’s management uses for making operating decisions and assessing performance of its various business activities. See Note 3 for more information on PNMR’s operating segments.

The following discussion and analysis should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known. Refer also to Disclosure Regarding Forward Looking Statements and to Part II, Item 1A. Risk Factors.

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PNM Electric

The table below summarizes operating results for PNM Electric:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
							(In millions)
Total revenues	$	323.8		$	304.3		$	19.5		$	797.2		$	777.9		$	19.3
Cost of energy	108.7			98.0			10.7			279.4			264.1			15.3
Gross margin	215.1			206.2			8.8			517.8			513.8			4.0
Operating expenses	102.1			102.5			(0.4		)	329.5			318.4			11.1
Depreciation and amortization	25.1			23.1			2.0			71.7			68.9			2.8
Operating income	87.9			80.7			7.2			116.6			126.5			(9.9		)
Other income (deductions)	(1.8		)	6.4			(8.2		)	16.2			25.6			(9.4		)
Net interest charges	(18.5		)	(18.0		)	(0.5		)	(54.6		)	(54.5		)	(0.1		)
Earnings before income taxes	67.6			69.1			(1.5		)	78.2			97.7			(19.5		)
Income (taxes) benefit	(25.1		)	(25.9		)	0.8			(26.6		)	(34.7		)	8.1
Valencia non-controlling interest	(4.1		)	(3.9		)	(0.2		)	(10.8		)	(10.3		)	(0.5		)
Preferred stock dividend requirements	(0.1		)	(0.1		)	—			(0.4		)	(0.4		)	—
Segment earnings	$	38.3		$	39.1		$	(0.8	)	$	40.5		$	52.2		$	(11.7	)

The table below summarizes the significant changes to total revenues, cost of energy, and gross margin:

	2011/2010 Change
	Three Months Ended September 30,									Nine Months Ended September 30,
	Total			Cost of			Gross			Total			Cost of			Gross
	Revenues			Energy			Margin			Revenues			Energy			Margin
							(In millions)
Retail rate increases	$	10.0		$	—		$	10.0		$	13.1		$	—		$	13.1
Retail load, fuel, and transmission	15.3			10.4			4.9			27.7			17.6			10.1
Unregulated margins	(9.9		)	0.4			(10.3		)	(29.5		)	1.0			(30.5		)
Net unrealized economic hedges	4.1			(0.1		)	4.2			8.0			(3.3		)	11.3
Total increase	$	19.5		$	10.7		$	8.8		$	19.3		$	15.3		$	4.0

77

The following table shows PNM Electric operating revenues by customer class, including intersegment revenues and average number of customers:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011		2010			Change			2011		2010			Change
			(In millions, except customers)
Residential	$	124.8	$	111.7		$	13.1		$	291.4	$	275.3		$	16.1
Commercial	115.7		107.8			7.9			287.8		272.4			15.4
Industrial	28.0		23.7			4.3			71.3		64.7			6.6
Public authority	7.4		6.8			0.6			17.8		16.2			1.6
Other retail	2.7		2.4			0.3			7.3		7.4			(0.1		)
Transmission	14.3		12.2			2.1			35.3		31.0			4.3
Firm requirements wholesale	8.1		8.3			(0.2		)	25.1		23.4			1.7
Other sales for resale	19.8		32.5			(12.7		)	57.4		91.7			(34.3		)
Mark-to-market activity	3.0		(1.1		)	4.1			3.8		(4.2		)	8.0
	$	323.8	$	304.3		$	19.5		$	797.2	$	777.9		$	19.3
Average retail customers (thousands)	503.8		501.8			2.0			503.7		501.4			2.3

The following table shows PNM Electric GWh sales by customer class:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011	2010	Change		2011	2010	Change
			(Gigawatt hours)
Residential	1,006.0	967.9	38.1		2,587.2	2,570.6	16.6
Commercial	1,130.0	1,140.2	(10.2	)	3,060.2	3,045.9	14.3
Industrial	429.4	371.3	58.1		1,187.8	1,085.1	102.7
Public authority	84.1	80.5	3.6		214.1	198.3	15.8
Firm requirements wholesale	154.6	165.7	(11.1	)	481.0	506.0	(25.0	)
Other sales for resale	580.4	546.9	33.5		1,709.9	1,632.3	77.6
	3,384.5	3,272.5	112.0		9,240.2	9,038.2	202.0

On August 21, 2011, PNM implemented a $72.1 million annual non-fuel rate increase for its retail customers, including those customers formerly served by TNMP, which improved revenues and margins by $10.0 million. In addition, PNM was allowed to implement a FPPAC for its PNM South retail customers. Increase in retail loads was driven primarily by warmer weather in the third quarter of 2011, which improved revenues by $6.0 million. Higher transmission revenues associated with new long-term point to point customers and the June 1, 2011 implementation of the $11.1 million requested annual rate increase, which is subject to refund pending final outcome of the case, improved revenues and margins, partially offset by refunds received in the third quarter of 2010 from the DOE regarding spent nuclear fuel and refunds related to fixed gas transportation costs.

Unregulated revenues and margins associated with PNM's share of PVNGS Unit 3, which is excluded from retail regulation, decreased revenues and margins in 2011. At December 31, 2010, long-term tolling agreements for the output of PVNGS Unit 3, which contained favorable pricing terms, expired. Although PNM has entered into contracts to sell the output of PVNGS Unit 3 for 2011, the prices received under the 2011 agreements are significantly below those received in 2010 due to lower market prices.

Changes in unrealized mark-to-market gains and losses are based on economic hedges in place for market sales and fuel costs not covered under the FPPAC. Unrealized gains of $4.1 million for the nine months ended September 30, 2011 compared to unrealized losses of $7.2 million for the nine months ended September 30, 2010, increased gross margin by $11.3 million. Changes in unrealized mark-to-market gains and losses for the three months ended September 30, 2011 increased gross margin by $4.2 million compared to 2010.

78

Operating expenses reflect reduced maintenance costs of $0.8 million for the three months ended September 30, 2011, primarily associated with improved plant performance at SJGS. In addition, production expenses were reduced by $1.4 million due to reallocation of previously incurred variable energy costs among the owner participants of Luna. Lower administrative and general expenses, including outside services and maintenance contracts, reduced allocation of corporate costs, and lower incentive compensation expense further lowered operating expenses, which were partially offset by an increase in expense for recently renewed transmission rights-of-way agreements, higher property taxes associated with increased investment in transmission and distribution assets, and an adjustment of $3.4 million for gross receipts tax recorded in the three months ended September 30, 2011. For the nine months ended September 30, 2011, operating expenses reflect regulatory disallowances of $17.5 million, which were recorded as of June 30, 2011, resulting from proceedings before the NMPRC relating to PNM's 2010 Electric Rate Case. See Note 16. No such costs were incurred in 2010.

For the three and nine months ended September 30, 2011, depreciation and amortization costs increased as a result of higher depreciable plant amounts, primarily associated with transmission and distribution assets.

For the three months ended September 30, 2011, impairment losses on NDT assets and increased fees and expenses associated with income tax payments of the NDT reduced other income by $7.6 million. For the nine months ended September 30, 2011, realized gains on the NDT assets offset the impairment losses taken in the third quarter, resulting in an increase to other income of $3.3 million. For the three and nine months ended September 30, 2011, further reductions in other income were $0.3 million and $2.0 million due to lower capitalization of the equity portion of AFUDC, and $0.8 million and $2.4 million in lower interest income on the PVNGS lessor notes due to a lower outstanding balance. For the nine months ended September 30, 2011, other income is lower in 2011 due to an $8.5 million settlement associated with the Republic Savings Bank litigation received in the first quarter of 2010.

For the nine months ended September 30, 2011, lower interest rates on debt refinanced in the second quarter of 2010 reduced interest charges are offset by reductions in the capitalization of the debt portion of AFUDC due to lower capitalization rates.

TNMP Electric

The table below summarizes the operating results for TNMP Electric:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
							(In millions)
Total revenues	$	67.0		$	61.2		$	5.8		$	180.8		$	162.0		$	18.8
Cost of energy	10.3			9.3			1.0			30.7			27.4			3.3
Gross margin	56.7			51.9			4.8			150.1			134.6			15.5
Operating expenses	22.5			20.7			1.8			67.4			58.5			8.9
Depreciation and amortization	12.7			11.6			1.1			33.7			31.7			2.0
Operating income	21.6			19.6			2.0			49.0			44.3			4.7
Other income (deductions)	0.3			0.1			0.2			0.9			0.7			0.2
Net interest charges	(7.3		)	(7.7		)	0.4			(21.9		)	(23.5		)	1.6
Earnings before income taxes	14.6			12.1			2.5			28.0			21.5			6.5
Income (taxes)	(5.7		)	(4.7		)	(1.0		)	(10.8		)	(8.5		)	(2.3		)
Segment earnings	$	8.9		$	7.3		$	1.6		$	17.1		$	13.1		$	4.0

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The table below summarizes the significant changes to total revenues, cost of energy, and gross margin:

	2011/2010 Change
	Three Months Ended September 30,							Nine Months Ended September 30,
	Total		Cost of		Gross			Total		Cost of		Gross
	Revenues		Energy		Margin			Revenues		Energy		Margin
					(In millions)
Rate increases	$	1.7	$	—	$	1.7		$	6.7	$	—	$	6.7
Customer usage/load	1.7		—		1.7			4.6		—		4.6
Transmission cost recovery	0.4		1.0		(0.6		)	4.9		3.3		1.6
Other	2.0		—		2.0			2.6		—		2.6
Total increase	$	5.8	$	1.0	$	4.8		$	18.8	$	3.3	$	15.5

The following table shows TNMP 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,
	2011		2010		Change			2011		2010		Change
			(In millions, except consumers)
Residential	$	34.5	$	27.8	$	6.7		$	77.8	$	66.8	$	11.0
Commercial	21.7		20.2		1.5			62.0		57.4		4.6
Industrial	3.3		3.0		0.3			9.5		9.0		0.5
Other	7.5		10.2		(2.7		)	31.5		28.8		2.7
	$	67.0	$	61.2	$	5.8		$	180.8	$	162.0	$	18.8
Average consumers (thousands) (1)	232.2		229.9		2.3			231.3		229.2		2.1

(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 First Choice or any other REP to provide energy. The average consumers reported above include 66,273 and 73,873 consumers for the three months ended September 30, 2011 and 2010, and 67,549 and 76,611 for the nine months ended September 30, 2011 and 2010, who have chosen First Choice as their REP. These consumers are also included as customers in the First Choice segment.

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

	Three Months Ended September 30,			Nine Months Ended September 30,
	2011	2010	Change	2011	2010	Change
			(Gigawatt hours(1))
Residential	1,015.0	927.6	87.4	2,319.4	2,182.8	136.6
Commercial	703.7	671.9	31.8	1,825.7	1,736.8	88.9
Industrial	675.2	580.3	94.9	1,931.1	1,674.2	256.9
Other	28.7	26.8	1.9	82.5	77.3	5.2
	2,422.6	2,206.6	216.0	6,158.7	5,671.1	487.6

(1) The GWh sales reported above include 324.1 and 325.9 GWhs for the three months ended September 30, 2011 and 2010, and 775.3 and 822.3 GWhs for the nine months ended September 30, 2011 and 2010 used by consumers, who have chosen First Choice as their REP. These GWhs are also included below in the First Choice segment.

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For the three and nine months ended September 30, 2011, revenues and margins increased due to the implementation of a $10.25 million base rate increase beginning February 1, 2011 and a transmission rate increase in May 2010. In 2011, changes to Texas retail electric rules allow distribution providers to defer into a regulatory asset or liability the difference between wholesale transmission costs charged to the distribution provider and the revenues it charges its customers for these costs. Previously, distribution providers had no mechanism to capture these differences between its transmission cost recovery filings and the revenues collected. For the three months ended September 30, 2011, gross margins were reduced reflecting the pass-through of these costs in 2011 versus gross margin recorded in prior year. For the nine months ended September 30, 2011, gross margins increased by $1.6 million due to this mechanism. In the third quarter of 2011, retail revenues and margins increased by $1.7 million due to higher retail loads driven primarily by warmer temperatures.

On August 11, 2011, TNMP implemented a surcharge for its advanced meter deployment. The surcharge is to be collected for a 12 year period and will recover TNMP's investment in advanced meter systems. The surcharge mechanism has a true-up mechanism, which allows for TNMP to match its revenues collected against the expenses incurred and allow for an earned return on its investments. In the third quarter of 2011, revenues, net of deferrals, increased by $0.6 million for this surcharge, which offset increases in operating expenses and depreciation, associated with the advanced meter deployment.

TNMP continues to focus on maintenance activities in the Gulf coast region of TNMP's operations due to unprecedented drought conditions, increasing operating expenses by $0.4 million and $1.1 million for the three and nine months ended September 30, 2011. For the three months ended September 30, 2011, higher street rental taxes of $0.3 million as a result of increased load, increased allocation of corporate overhead costs of $0.5 million, and higher labor and vegetation management activities further increased operating expenses. For the nine months ended September 30, 2011, TNMP recorded a regulatory disallowance expense of $3.9 million based on a ruling in the 3^rd Court of Appeals regarding the retroactive application of the interest rate used to calculate the return on TNMP's CTC regulatory assets. See Note 10. In addition, a $0.2 million write-off of rate case expenses associated with the 2010 TNMP rate case increased operating expenses.

The increase in depreciation and amortization relates to Hurricane Ike restoration cost, CTC regulatory assets, and increases in plant.

TNMP amended its revolving credit facility in December 2010, which extended its expiration to December 2015. The amendment resulted in lower fees and more favorable interest rates, which reduced interest charges in 2011.

First Choice

The table below summarizes the operating results for First Choice:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
							(In millions)
Total revenues	$	171.0		$	149.7		$	21.3		$	405.5		$	384.0		$	21.5
Cost of energy	144.0			119.4			24.6			303.3			296.5			6.8
Gross margin	27.0			30.4			(3.4		)	102.2			87.6			14.6
Operating expenses	25.1			24.0			1.1			67.7			65.7			2.0
Depreciation and amortization	0.3			0.2			0.1			1.0			0.7			0.3
Operating income	1.5			6.2			(4.7		)	33.5			21.2			12.3
Other income (deductions)	(0.1		)	(0.1		)	—			(0.4		)	(0.1		)	(0.3		)
Net interest charges	(0.2		)	(0.4		)	0.2			(0.5		)	(1.1		)	0.6
Earnings before income taxes	1.2			5.8			(4.6		)	32.6			20.0			12.6
Income (taxes)	(0.6		)	(2.2		)	1.6			(11.8		)	(7.4		)	(4.4		)
Segment earnings	$	0.6		$	3.6		$	(3.0	)	$	20.7		$	12.7		$	8.0

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

	2011/2010 Change
	Three Months Ended September 30,									Nine Months Ended September 30,
	Total			Cost of			Gross			Total			Cost of			Gross
	Revenues			Energy			Margin			Revenues			Energy			Margin
							(In millions)
Weather	$	11.7		$	7.9		$	3.8		$	17.1		$	11.3		$	5.8
Customer growth/usage	18.4			13.3			5.1			34.5			24.0			10.5
Retail margins	(8.8		)	14.7			(23.6		)	(30.1		)	6.8			(37.0		)
Unrealized economic hedges	—			(11.3		)	11.3			—			(35.3		)	35.3
Total increase (decrease)	$	21.3		$	24.6		$	(3.4	)	$	21.5		$	6.8		$	14.6

The following table shows First Choice operating revenues by customer class, including intersegment revenues, and actual number of customers:

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011		2010		Change			2011		2010		Change
			(In millions, except customers)
Residential	$	104.2	$	98.4	$	5.8		$	241.9	$	248.4	$	(6.5	)
Commercial	62.5		46.1		16.4			152.2		122.5		29.7
Other	4.3		5.2		(0.9		)	11.4		13.1		(1.7		)
	$	171.0	$	149.7	$	21.3		$	405.5	$	384.0	$	21.5
Actual customers (thousands) (1,2)	223.1		215.3		7.8			223.1		215.3		7.8

(1) See note above in the TNMP Electric segment discussion about the impact of TECA.

(2) Due to the competitive nature of First Choice’s business, actual customer counts are presented in the table above as a more representative business indicator than the average consumers that are shown in the table for TNMP.

The following table shows First Choice GWh electric sales by customer class:

	Three Months Ended September 30,			Nine Months Ended September 30,
	2011	2010	Change	2011	2010	Change
		(Gigawatt hours) (1)
Residential	812.8	732.0	80.8	1,871.5	1,831.3	40.2
Commercial	569.5	410.8	158.7	1,397.8	1,038.2	359.6
	1,382.3	1,142.8	239.5	3,269.3	2,869.5	399.8

(1) See note above in the TNMP Electric segment discussion about the impact of TECA.

During the three and nine months ended September 30, 2011, total revenues increased due to favorable weather and an increase in both MWh sales and number of customers, which were partially offset by a decrease in the average revenue rates. Due to extreme temperatures during the three months ended September 30, 2011, First Choice incurred significantly higher purchased power costs per MWh. These higher energy costs more than offset the increase in revenues resulting in decreased gross margin, excluding the effects of mark-to-market on unrealized economic hedges.

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First Choice manages its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins.  Accordingly, First Choice has forward contracts for the purchase of energy to cover the future load requirements for most of its fixed price sales contracts.  Gains or losses on unrealized economic hedges represent changes in unrealized fair value estimates related to these forward supply contracts.  Changes in the fair value of supply contracts that are not designated or are not eligible for hedge or normal purchase and sales accounting are marked to market through current period earnings as required by GAAP. First and third quarter of 2010 market energy price decreases were partially offset by second quarter 2010 activity. During 2011, market energy prices increased, which resulted in unrealized mark-to-market gains on certain of First Choice's forward supply contracts.  First Choice is not required to mark the related fixed price sales contracts to market, which would likely show offsetting gains and losses as market energy prices fluctuate.  Year-to-date gains on unrealized economic hedges increased segment earnings by $1.7 million in 2011 compared with losses of $33.6 million in 2010. The mark-to-market gains or losses are not necessarily indicative of the amounts that will be realized upon settlement or the retail margin First Choice will realize.

The allowance for uncollectible accounts and related bad debt expense is based on collections and write-off experience.  In 2009, the customer default rates experienced were above historic levels due to overall economic conditions, higher average final bills, and an increase in customer churn. Recently, lower customer departures, lower default rates, and an increase in commercial customers have reduced bad debt. As a result, year-to-date 2011 bad debt expense decreased, which increased segment earnings by $1.3 million compared to 2010. This reduction can be partially attributed to several initiatives undertaken by management to reduce bad debt expense.  These initiatives include efforts to reduce the default rate experienced for customers switching to another REP, focusing marketing efforts on commercial customers, and identifying new customers prospects with established payment patterns and desirable customer payment attributes.

During 2011, increases in marketing and operational costs were partially offset by a decrease in incentive compensation expense. The increases in operational costs were primarily related to developing an option for customers to pre-pay for energy deliveries and establishing local office locations. Interest expense decreased in 2011 compared to 2010 primarily due to lower short-term debt.

As discussed in Note 16, PNMR completed the sale of First Choice to Direct Energy on November 1, 2011. Therefore, PNMR results of operation will not include First Choice after October 31, 2011.

Corporate and Other

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
				(In millions)
Total revenues	$	(12.2	)	$	(11.5	)	$	(0.7	)	$	(30.8	)	$	(31.0	)	$	0.2
Cost of energy	(12.2		)	(11.5		)	(0.7		)	(30.6		)	(30.7		)	0.1
Gross margin	—			(0.1		)	0.1			(0.1		)	(0.3		)	0.2
Operating expenses	(1.6		)	(3.0		)	1.4			(7.2		)	(10.1		)	2.9
Depreciation and amortization	4.3			4.1			0.2			12.8			12.3			0.5
Operating income (loss)	(2.7		)	(1.1		)	(1.6		)	(5.7		)	(2.5		)	(3.2		)
Equity in net earnings (loss) of   Optim Energy	—			2.5			(2.5		)	—			(5.7		)	5.7
Other income (deductions)	(1.7		)	(1.6		)	(0.1		)	(5.0		)	(4.5		)	(0.5		)
Net interest charges	(5.1		)	(5.3		)	0.2			(15.2		)	(15.5		)	0.3
Earnings (loss) before income     taxes	(9.6		)	(5.5		)	(4.1		)	(26.0		)	(28.2		)	2.2
Income (taxes) benefit	5.4			4.1			1.3			12.0			13.2			(1.2		)
Segment earnings (loss)	$	(4.1	)	$	(1.5	)	$	(2.6	)	$	(13.9	)	$	(15.0	)	$	1.1

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The Corporate and Other Segment includes consolidation eliminations of revenues and cost of energy between business segments, primarily related to TNMP's sale of transmission, distribution, and tariffed discretionary services to First Choice. Corporate and Other also includes equity in Optim Energy's results of operations through December 31, 2010, which are further explained below.

Operating expenses increased primarily due to legal and consulting expenses incurred related to assessments of strategic alternatives for PNMR's competitive businesses.

Optim Energy

As discussed above and in Note 11, PNMR’s investment in Optim Energy was reduced to zero at December 31, 2010 due to the determination that the investment was fully impaired. In accordance with GAAP, PNMR has not recorded losses (or income) associated with its investment in Optim Energy in 2011 as PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources. Accordingly, Optim Energy has no impact on PNMR's 2011 balance sheet, statement of earnings, and statement of cash flows. Therefore, summarized financial information for Optim Energy is not presented. As discussed above, PNMR entered into agreements on September 23, 2011 that reduced PNMR's ownership in Optim Energy from 50% to 1%. PNMR accounted for its investment in Optim Energy using the equity method of accounting until September 23, 2011 and is using the cost method thereafter.

In 2010, Optim Energy's strategy and near-term focus was on utilizing cash flow from operations to reduce debt and optimizing its generation assets as a stand-alone independent power producer.  Optim's results of operations were primarily determined by the prices at which its power is sold and its fuel to generate power, principally natural gas, is procured. Power prices in the ERCOT market are directly correlated to natural gas prices. The markets for power and natural gas were depressed in 2010. Optim Energy had net earnings (loss) of $7.6 million and $(6.8) million in the three months and nine months ended September 30, 2010. PNMR recognized net earnings (loss) from Optim Energy of $2.5 million and $(5.7) million in the three months and nine months ended September 30, 2010. Such amounts include amortization of a basis difference between PNMR's recorded investment in Optim Energy and 50 percent of Optim Energy’s equity.

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR’s cash flows for the nine months ended September 30, 2011 compared to September 30, 2010 are summarized as follows:

	Nine Months Ended September 30,
	2011				2010			Change
				(In millions)
Net cash flows from:
Operating activities	$	198.5			$	216.6		$	(18.1	)
Investing activities	(204.8		)		(170.8		)	(34.0		)
Financing activities	16.7				(35.3		)	52.0
Net change in cash and cash equivalents	$	10.4			$	10.5		$	(0.1	)

The changes in PNMR's cash flows from operating activities relate primarily to lower net income tax refunds in 2011 of $3.7 million compared to $98.8 million in 2010 and higher purchased power costs at First Choice due to extreme temperatures for the three months ended September 30, 2011. The decreases were partially offset by the January 2010 payment of the $31.9 million settlement of the California energy crisis legal proceeding and decreases in posted collateral requirements of $28.1 million at First Choice and $9.3 million at PNM. Improved collections under the FPPAC at PNM of $22.8 million also contributed to the change.

PNMR's cash flows from investing activities relate primarily to increases in construction expenditures in 2011 of $38.3 million at PNM and $20.8 million at TNMP, partially offset by a decrease in payments for rights-of-way renewals in 2011 of $4.8 million at PNM and the $17.6 million investment in Optim Energy in 2010. Construction expenditures were funded primarily

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through cash flows from operating activities and short-term borrowings in both 2011 and 2010.

The changes in cash flows from financing activities relate primarily to $73.0 million increase in net short-term borrowings. In addition, payments received on PVNGS firm-sales contract arrangements were reduced to $2.6 million in 2011 compared to $22.9 million in 2010 as those contracts expired on December 31, 2010.

Financing Activities

See Note 7 for information concerning the Company’s financing activities during the nine months ended September 30, 2011. The Company has from time to time refinanced or repurchased portions of its outstanding debt. Depending on market conditions, the Company may refinance other debt issuances or make additional debt repurchases in the future. Additional information on the Company’s financing activities is contained in Note 6 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

As discussed above and in Note 16, PNMR completed the sale of First Choice on November 1, 2011 with PNMR receiving $270.0 million plus $59.3 for estimated working capital, which amount is subject to adjustment based on the actual amounts of certain components of working capital at October 31, 2011. At the time of entering into the agreement to sell First Choice, the Board approved using proceeds from the sale to repurchase of up to $75 million of PNM Resources’ long-term debt, the repurchase of preferred stock, and a common stock repurchase program. The aggregate amount of the authorized equity repurchases is up to $230 million. Other than the preferred stock repurchase and the pending tender offer to repurchase up to $50 million of PNMR's outstanding 9.25% senior unsecured notes, no agreements have been entered into regarding these purchases. The amount and timing of additional purchases will depend on a number of factors, including the price and availability of PNMR debt and shares, trading volume, and general market conditions. On November 1, 2011, PNMR utilized a portion of the proceeds from the sale of First Choice to repay short-term debt incurred to finance the October 5, 2011 payment for the purchase of PNMR's Series A preferred stock, as well as all other PNMR borrowings under the PNMR Revolving Credit Facility. In addition, on November 1, 2011, PNMR loaned $63.8 million to PNM under their intercompany loan agreement and PNM repaid all borrowings under the PNM Revolving Credit Facility.

Capital Requirements

Total capital requirements consist of construction expenditures and cash dividend requirements for both common and preferred stock. On September 23, 2011, PNMR entered into an agreement to purchase all of its outstanding convertible preferred stock, Series A (the “Preferred Stock”) pursuant to a Sale and Purchase Agreement dated September 23, 2011 between PNMR and Cascade. The Preferred Stock was entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the Preferred Stock had been converted into common stock. The main focus of PNMR’s current construction program is upgrading generation resources, including renewable energy resources to be owned by PNM, upgrading and expanding the electric transmission and distribution systems, including investment in advanced meter systems at TNMP, and purchasing nuclear fuel. Projections, including amounts expended through September 30, 2011, for total capital requirements for 2011 are $408.6 million, including construction expenditures of $362.4 million. Total capital requirements for the years 2011-2015 are projected to be $1,604.4 million, including construction expenditures of $1,373.2 million. These amounts do not include the costs of any pollution control equipment that might ultimately be required as a result of EPA's final FIP decision issued on August 5, 2011, as discussed in Note 9. These estimates are under continuing review and subject to on-going adjustment, as well as to Board review and approval. PNM is reviewing the potential impacts of EPA's FIP decision on capital requirements.

During the nine months ended September 30, 2011, PNMR utilized cash generated from operations and cash on hand, as well as its liquidity arrangements, to meet its capital requirements, including construction expenditures.

TNMP has $50.0 million in borrowings, which are secured by first mortgage bonds, that are due in 2014. PNM has PCRBs of $39.3 million and $37.0 million that are subject to mandatory tender in 2015 and 2017. PNMR has senior unsecured notes of $192.6 that are due in 2015. PNMR and its subsidiaries have no other long-term debt that comes due prior to 2018, except for $7.2 million that is due in installments through 2013.

Liquidity

On October 31, 2011, PNMR entered into the PNMR Revolving Credit Facility, which has a financing capacity of $300.0 million and PNM entered into the PNM Revolving Credit Facility, which has a financing capacity of $400.0 million. These new

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facilities expire on October 31, 2016, and include two one-year extension options, subject to approval by a majority of the lenders and, with respect to the PNM Revolving Credit Facility, regulatory approval. The new credit facilities replace the $517.0 million PNMR Facility and the $368.0 million PNM Facility, both of which would have expired in August 2012. PNMR’s current liquidity arrangements include the PNMR Revolving Credit Facility, the PNM Revolving Credit Facility, and the TNMP Revolving Credit Facility, which expires in December 2015. These facilities provide short-term borrowing capacity and also allow letters of credit to be issued, which 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 when air conditioning loads are greater. In general, the Company relies on these credit facilities as the initial source to finance construction expenditures resulting in increased borrowings under the facilities over time. Depending on market and other conditions, the Company will periodically enter into arrangements for the sale of long-term debt and utilize the proceeds to reduce the borrowings under the credit facilities. Borrowings under the PNMR Facility ranged from $14.0 million to $37.0 million during the three months ended September 30, 2011 and from zero to $37.0 million during the nine months ended September 30, 2011. Borrowings under the PNM Facility ranged from $240.0 million to $298.0 million during the three months ended September 30, 2011 and from $190.0 million to $298.0 million during the nine months ended September 30, 2011. There have been no borrowings under the TNMP Revolving Credit Facility during 2011. At September 30, 2011, average interest rates were 1.48% for the PNMR Facility and 0.88% for the PNM Facility. PNMR also has a line of credit with a local financial institution that expires in August 2012. As of November 1, 2011, the Company had no short-term debt outstanding.

The Company’s credit facilities contain various financial and other covenants. The covenants, among other things, require minimum debt-to-capital ratios, limit asset sales, and restrict granting of liens. Noncompliance with certain terms of the credit facilities could require the repayment of outstanding amounts and commitments could be withdrawn.  An acceleration of the repayment under one agreement could trigger the acceleration of repayment under the others.  The Company was in compliance with all of the financial and other covenants at September 30, 2011.

The Company currently believes that its internal cash generation, existing credit arrangements, and access to public and private capital markets will provide sufficient resources to meet the Company’s capital requirements for the next twelve months. To cover the difference in the amounts and timing of cash generation and cash requirements, the Company intends to use short-term borrowings under its liquidity arrangements. However, if market conditions worsen, the Company may not be able to access the capital markets. In such event, the Company would seek to improve cash flows by reducing capital expenditures and PNM would consider seeking authorization for the issuance of first mortgage bonds in order to improve access to the capital markets, as well as any other alternatives that may remedy the situation at that time.

In addition to its 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 and debt maturities during the 2011-2015 period.

The Company’s ability, if required, to access the credit and capital markets at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, its results of operations, its credit ratings, its ability to obtain required regulatory approvals, and conditions in the financial markets. The credit ratings for PNMR, PNM, and TNMP were set forth under the heading Liquidity in the MD&A contained in the 2010 Annual Reports on Form 10-K. On September 26, 2011, S&P raised the credit ratings for PNMR, PNM, and TNMP and changed the outlook for each entity to positive. On November 1, 2011, Moody's raised the credit ratings for PNMR and TNMP. As of November 1, 2011, ratings on the Company's securities were as follows:

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

* Not applicable

A summary of liquidity arrangements as of November 1, 2011 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
Local lines of credit	5.0		—		—		5.0
Total financing capacity	$	305.0	$	400.0	$	75.0	$	780.0
Amounts outstanding as of November 1, 2011:
Revolving credit facility	$	—	$	—	$	—	$	—
Local lines of credit	—		—		—		—
Total short-term debt outstanding	—		—		—		—
Letters of credit	69.6		5.2		0.3		75.1
Total short–term debt and letters of credit	$	69.6	$	5.2	$	0.3	$	75.1
Remaining availability as of November 1, 2011	$	235.4	$	394.8	$	74.7	$	704.9
Invested cash as of November 1, 2011	$	166.7	$	—	$	—	$	166.7

The above table excludes intercompany debt. At November 1, 2011, PNM and TNMP had borrowings from PNMR under their intercompany loan agreements of $63.8 million and $5.4 million. Letters of credit for PNMR include $58.5 million that supported First Choice contractual arrangements. The First Choice letters of credit are in the process of being replaced by similar letters of credit from the purchaser of First Choice, which process is anticipated to be completed by November 30, 2011. The remaining availability under the revolving credit facilities 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 equity and debt 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 PNMR common stock through the PNM Resources Direct Plan under a separate SEC shelf registration statement that expires in August 2012. PNM has a shelf registration statement for the issuance of up to $440.0 million of senior unsecured notes that will expire in May 2014.

As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K, disruption in the credit markets has had a significant adverse impact on a number of financial institutions and several of the financial institutions that the Company deals with have been impacted. However, at this point in time, the Company’s liquidity has not been materially impacted and management does not expect that it will be materially impacted in the near-future.

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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, a 132 MW gas-fired generating plant. These arrangements help ensure PNM the availability of lower-cost generation needed to serve customers. See MD&A – Off-Balance Sheet Arrangements and Note 7 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

Commitments and Contractual Obligations

PNMR, PNM, and TNMP have contractual obligations for long-term debt, operating leases, purchase obligations, and certain other long-term liabilities. See MD&A – Commitments and Contractual Obligations in the 2010 Annual Reports on Form 10-K. APS, on behalf of the Four Corners participants, negotiated amendments to the Four Corners facility lease with the Navajo Nation, which would extend the lease to 2041. The amendments have been approved by the Navajo Nation Council and signed by the Nation’s President. The effectiveness of the amendments also requires the approval of the DOI, which the Four Corners participants will pursue. PNM’s share of the annual lease payments is $0.9 million beginning in 2016.

Contingent Provisions of Certain Obligations

As discussed in the 2010 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. The contingent provisions 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 and the requirement to provide security under certain contractual agreements. The Company believes its financing arrangements are sufficient to meet the requirements of the contingent provisions.

Capital Structure

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

	September 30, 2011		December 31, 2010
PNMR
PNMR common equity	50.2	%	47.8	%
Convertible preferred stock	—		3.1	%
Preferred stock of subsidiary	0.4	%	0.4	%
Long-term debt	49.4	%	48.7	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	51.9	%	51.3	%
Preferred stock	0.5	%	0.5	%
Long-term debt	47.6	%	48.2	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	59.9	%	59.4	%
Long-term debt	40.1	%	40.6	%
Total capitalization	100.0	%	100.0	%

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OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In 2010, PNMR’s interests in generating plants, through PNM, emitted approximately 6.5 million metric tons of CO₂, which comprises the vast majority of its GHG.  By comparison, the total GHG in the United States in 2009, the latest year for which EPA has compiled this data, were approximately 6.6 billion metric tons, of which approximately 5.5 billion metric tons were CO₂.  According to EPA data, electricity generation accounted for approximately 2.2 billion metric tons, or 40%, of the CO₂ emissions.

PNM has several programs underway to reduce GHG from its generation fleet, thereby reducing its exposure to climate change regulation. See Note 10. PNM is building 22 MW of utility-scale solar generation located at five sites on PNM’s system throughout New Mexico, the first 17 MW of which were in service at October 31, 2011 and the rest will be complete by the end of 2011. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with an annual budget of over $17 million that saves an estimated 54 GWh of electricity per year. Over the next 19 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 12,870 GWh of electricity, which will avoid at least 6.1 million metric tons of CO₂ based upon projected emissions from PNM’s system-wide portfolio with and without these programs. These estimates are subject to change given that it is difficult to accurately estimate avoidance because of the many underlying variables with high uncertainty and complex interrelationships, including changes in demand for electricity.

Management periodically updates the Board on the matters discussed in this section and the Board regularly considers the 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. The Board monitors practices and procedures to assess the sustainability impacts of operations and products on the environment. This includes reviewing environmental management systems, monitoring the implementation of corporate environmental policy, monitoring the promotion of energy efficiency, and monitoring the use of renewable energy resources.

EPA Regulation

In April 2007, the U.S. Supreme Court held that EPA has the authority to regulate GHG under the CAA.  This decision has heightened the importance of this issue for the energy industry.   Although there continues to be debate over the details and best design for state and federal programs, the Company anticipates that EPA will continue to regulate GHG.  

In December 2009, EPA released its final endangerment finding stating that the atmospheric concentrations of six key greenhouse gases (CO₂, methane, nitrous oxides, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride) endanger the public health and welfare of current and future generations. The finding does not by itself impose any requirements on producers of GHG, but the finding sets the groundwork for EPA to regulate GHG from new and existing stationary sources, such as power plants, and new motor vehicles.

On May 13, 2010, EPA released the final PSD and Title V Greenhouse Gas Tailoring Rule. 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. As expected, the rule focuses on the largest sources of GHG, including fossil-fueled electric generating units. The final rule establishes three major phases for regulating GHG. Phase 1 became effective January 2, 2011 and addresses only those new or modified sources that were already subject to the PSD construction permit and Title V operating permit programs for other regulated emissions. Under Phase 1, such sources must comply with PSD permitting requirements, including best available control technology (“BACT”) analysis for GHG, if they construct a new unit or modify an existing unit that will result in an increase in GHG of greater than 75,000 tons per year. Phase 2 began July 1, 2011 and for the first time, 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 permitting requirements, even if they do not significantly increase emissions of any other pollutant. EPA has indicated that it will adopt a Phase 3, to be effective in July 2013, which may phase in even smaller GHG sources. All of PNM’s existing generating plants are potentially subject to the Tailoring Rule because of the magnitude of non-GHG, but the plants do not have any currently planned projects that would trigger PSD permitting for GHGs.

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On December 23, 2010, EPA announced a proposed rulemaking timeline for CAA NSPS for GHG from power plants and petroleum refineries. The rulemaking timeline is established in two proposed settlement agreements. On June 13, 2011, EPA announced that it would extend the deadline for proposing NSPS for GHG emissions from electric generating units from July 26, 2011 until September 30, 2011. However, on September 15, 2011, EPA announced it would further delay its proposal, citing the complexity of the rule, the amount of information it needed to consider, and its desire to make sure the proposal was "cost-effective and protective." EPA has not yet announced its new schedule to issue the proposal. The deadline for EPA to publish the final standards is still May 26, 2012. The CAA’s NSPS provisions include separate programs for new and modified facilities and for existing facilities. EPA will establish NSPS for new and modified facilities directly, while EPA will establish emission guidelines for existing facilities through a cooperative federal-state process.

EPA regulation of GHG from large stationary sources will impact PNM’s operations due to the Company’s reliance on fossil-fueled electric generation. The impact to PNM is unknown because the regulatory requirements, including BACT implications and NSPS requirements, are not yet defined. Impacts could involve investments in efficiency improvements and/or control technologies at the fossil-fueled generating plants. It is also possible that the costs of such improvements or technologies could impact the economic viability of some plants.

Federal Legislation

Prospects for enactment of legislation imposing a new or enhanced regulatory program to address climate change in the current Congress are extremely unlikely, although Congress could address these issues at a future time. Instead, EPA is likely the primary venue for GHG regulation over the next two years.

The Company 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.  The Company’s assessment includes assumptions regarding the specific GHG limits, the timing of implementation of these limits, the level of emissions allowances allocated and the level that must be purchased, the development of technologies for renewable energy and to reduce emissions, the cost of emissions allowances, the degree to which offsets may be used for compliance, and provisions for cost containment. Moreover, the assessment assumes various market reactions such as with respect to 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 would likely, among other things, result in significant compliance costs, including significant capital expenditures by the Company, and could jeopardize the economic viability of certain generating facilities (see Note 9 – The Clean Air Act – Regional Haze).  In turn, these consequences would lead to increased costs to customers and could 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.  The Company’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 (see Note 10), showed that incorporation of the NMPRC required carbon emissions costs did not significantly change the resource decisions regarding future facilities over the next 20 years. 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.

In 2007, seven western states, including New Mexico, and three Canadian provinces entered into an accord, called the Western Regional Climate Action Initiative (the “WCI”), to reduce GHG from automobiles and certain industries, including utilities.   The WCI released design recommendations for elements of a regional cap-and-trade program in September 2008 and created several subcommittees to develop detailed implementation recommendations.   Under the WCI recommendations, GHG

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from the electricity sector and fossil fuel consumption of the industrial and commercial sectors would be capped at then current levels and subject to regulation starting in 2012.  Over time, producers would be required to reduce their GHG.  Implementation of the design elements for GHG reductions would fall to each state and province.  

On June 4, 2010, the NMED filed a petition with the EIB for the adoption of rules required to implement a WCI cap-and-trade program. A hearing was held in September 2010. On November 2, 2010, the EIB approved the NMED’s proposal to institute a regional cap-and-trade rule that would affect sources regulated by NMED that emit more than 25,000 metric tons of CO₂ per year. The cap would start with an emissions baseline established in 2011. NMED would grant allowances for free to regulated sources based on their baseline and a 2% annual reduction. In order to take effect, New Mexico and California must recognize each other as trading partners under the WCI regional trading program, which has not occurred. On October 20, 2011, the California Air Resources Board adopted a final cap-and-trade regulation that calls for quarterly auctions of GHG allowances starting in August 2012. Also, several market elements including allowance tracking and a trading market must be established by WCI. The EIB adopted the proposed rule in December 2010. PNM appealed the EIB’s decision and after court-sanctioned mediation, PNM and EIB filed a joint motion asking the court of appeals to remand the case to the EIB for a period of 180 days. The court of appeals granted the motion on July 19, 2011. PNM and other industry parties filed a Petition for Regulatory Change (Repeal) of the NMED Rule on July 15, 2011. On August 1, 2011, the EIB agreed to hear the repeal petition. PNM filed testimony to support repealing the rule on September 15, 2011. In PNM's testimony the cost of compliance with this rule is estimated based on the recent IRP to range, depending upon assumptions on allowance price and availability, between $433 million and $841 million over the planning period. Hearings on the petition to repeal the rule are scheduled to begin on November 8, 2011. If EIB does not repeal the NMED rule, and implements the cap-and-trade program, PNM will seek to recover in rates any increased costs due to the rule.

In December 2008, New Energy Economy (“NEE”), a non-profit environmental advocacy organization, petitioned the EIB to amend existing regulations and adopt new regulations that would reduce GHG from certain sources regulated by the State of New Mexico. Following extensive litigation regarding the EIB’s authority to regulate GHG, which did not resolve the issue, the rulemaking hearing on the NEE petition concluded on October 5, 2010. On December 8, 2010, the EIB adopted a modified version of the petition. The modifications pushed the effective date to January 1, 2013 or six months after NMED’s cap-and-trade rule is no longer in force, whichever is later. PNM filed testimony in the rulemaking hearing estimating the cost of electricity to PNM’s customers would increase by approximately $8 million per year if the NEE’s proposed rule is adopted. On January 25, 2011, PNM appealed the EIB’s decision and, after court-sanctioned mediation, PNM and EIB filed a joint motion asking the court of appeals to remand the case to the EIB for a period of 180 days. The court of appeals granted the motion on July 19, 2011. PNM and other industry parties filed a Petition for Regulatory Change (Repeal) of the NEE Rule on July 15, 2011. At its meeting on August 1, 2011, the EIB decided that it will conduct hearings to determine whether or not the NEE Rule should be repealed. PNM filed testimony to support repealing the rule on October 7, 2011. In PNM's testimony the cost of compliance with this rule is estimated to cost $541 million over the 20 year IRP planning period. Hearings on the petition to repeal the rule are scheduled to begin on December 5, 2011. If the EIB does not repeal the NEE Rule, and it takes effect, PNM will seek to recover in rates any increased costs due to the rule.

In April 2011, NEE moved to intervene in PNM's appeal, which motion was denied by the court of appeals. After further procedural steps in the court of appeals, NEE filed a Writ of Superintending Control in the New Mexico Supreme Court in June 2011 and also sought to vacate the remand order entered by the court of appeals. After oral argument, the Supreme Court held on July 27, 2011 that NEE has the right to be a party on appeal. However, the remand of PNM's appeal, in which NEE is now an appellee, remains in effect.

Implementation of the NMED cap-and-trade rule is currently in doubt. It is possible future action by the EIB, the court, or

the legislature might cause these rules to be repealed. In addition, the Governor of New Mexico established a small-business task force to review recent regulations shortly after her inauguration. The task force issued its recommendations on April 1, 2011. The recommendations include changing New Mexico’s status in the WCI from participant to observer and revising the cap-and-trade rule approved in November 2010. New Mexico is no longer a participant in the WCI. However, the state is continuing to work with other states and provinces on other North American climate initiatives and clean energy policies and strategies.

Impact of International Accords, Indirect Consequences, and Physical Impacts

Approximately 82.8% of PNM’s owned and leased generating capacity at December 31, 2010 consists of coal or gas-fired generation that produces GHG, all of which is located within the United States. The Company does not anticipate any direct impact from any near term international accords. Based on current forecasts, the Company does not expect its output of GHG to

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increase significantly in the near-term. Many factors affect the amount of GHG, including plant performance.  For example, if PVNGS experienced prolonged outages, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG. Because of the Company’s dependence on fossil-fueled generation, any legislation that imposes a limit or cost on GHG will impact the cost at which electricity is produced. While PNM expects to be entitled to recover that cost through rates, the timing and outcome of proceedings for cost recovery is 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 the Company.

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 possible 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 basin. PNM also has a supplemental water contract in place with the Jicarilla Tribe to help address any water shortages from primary sources. The contract expires 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 Company owned facilities, which disrupt the ability to generate, transmit, and/or distribute energy, hurricanes can temporarily reduce customers’ usage and demand for energy.

Impact of Earthquake and Tsunami in Japan on Nuclear Energy Industry

Following the March 11, 2011 earthquake and tsunami in Japan, the NRC commissioners launched a two-pronged review of U.S. nuclear power plant safety. The NRC supported the establishment of an agency task force to conduct both a near- and long-term analysis of the lessons that can be learned from the situation in Japan. The near-term task force issued a report on July 12, 2011, and on October 3, 2011, the NRC staff issued a plan for implementing the near-term task force's recommendations.

On October 18, 2011, the NRC commissioners directed the NRC staff to implement, without delay, the near-term task force recommendations, subject to certain conditions. One such condition is that the agency should strive to complete and implement lessons learned from the earthquake and tsunami in Japan within five years. A second condition is that the staff should designate the recommendation for a rulemaking to address extended loss of offsite power to be completed within 24 to 30 months.

Until further action is taken by the NRC as a result of this event, the Company cannot predict any financial or operational impacts on PVNGS or PNM.

Financial Reform Legislation

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act, which is intended to improve regulation of financial markets, was signed into law. Many of the rules required to implement the legislation have not yet been finalized. The Company is currently evaluating this legislation and cannot predict the impact it may have on the Company’s financial condition, results of operations, cash flows, or liquidity.

Other Matters

See Notes 9 and 10 herein and Notes 16, 17, and 18 in the 2010 Annual Reports on Form 10-K for a discussion of commitments and contingencies, rate and regulatory matters, and environmental issues facing the Company.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires Company management to select and apply accounting policies that best provide the framework to report the results of operations and financial position for PNMR, PNM, and TNMP. The selection and application of those policies requires management to make difficult, subjective, and/or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

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As of September 30, 2011, there have been no significant changes with regard to the critical accounting policies disclosed in PNMR’s, PNM’s, and TNMP’s 2010 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.

MD&A FOR PNM

RESULTS OF OPERATIONS

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

MD&A FOR TNMP

RESULTS OF OPERATIONS

TNMP operates in only one reportable segment, TNMP Electric, 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 and 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 flow, 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 their costs and earn their allowed returns in their regulated jurisdictions,

• The ability of the Company to successfully forecast and manage its operating and capital expenditures, particularly in the context of a future test year rate case with respect to PNM,

• The performance of state, regional, and national economies and the resulting impacts on the electricity usage of the Company’s customers,

• The performance of generating units, including PVNGS, SJGS, and Four Corners, transmission systems, and distribution systems, which could be negatively affected by major equipment failures, major weather disruptions, disruptions in fuel supply, cyber and physical security breaches, and other significant operational issues,

• State and federal regulation or legislation relating to climate change, reduction of GHG, CCBs, NOx, and other power plant emissions, including the risk that the Company may have to commit to substantial capital investments and additional operating costs to comply with new environmental requirements, including possible future requirements to address regional haze regulations and related BART requirements and concerns about global climate change, and the resultant impacts on the operations and economic viability of generating plants in which PNM has interests,

• Uncertainties surrounding the mine fire incident at the mine supplying coal to SJGS, including potential impacts on the operations of SJGS, the costs of fuel, and the cap on the annual amounts recoverable through PNM's FPPAC,

• State and federal regulatory, legislative, and judicial decisions and actions, including the outcomes of PNM’s pending transmission and firm requirements power rate cases and appeals of prior regulatory proceedings,

• Uncertainty surrounding the status of PNM’s participation in jointly-owned generation projects resulting from the scheduled expiration of the operational documents for the projects beginning in 2016 and potential changes in the objectives of the participants in the projects,

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

• Financial and operational risks at PVNGS relating to any increased regulatory review and actions in response to the events at the Fukushima Daiichi Nuclear Power Plant in Japan,

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• The risk that recently enacted reliability standards regarding available transmission capacity may reduce certain PNM transmission rights used to transmit its generation resources and provide access to transmission customers resulting in a need to purchase additional transmission capacity, reduce sales of transmission capacity, or operate generation facilities less economically,

• The risks associated with completion of generation, transmission, distribution, and other projects, including construction delays and unanticipated cost overruns,

• The ability of PNM to successfully defend the utilization of a future test year in its electric rate filings with the NMPRC, including PNM’s ability to withstand challenges by regulators and intervenors,

• The ability of PNM to meet the renewable energy requirements established by the NMPRC, including the resource diversity requirement, within the specified cost parameters,

• The risk that replacement power costs incurred by PNM related to not meeting the specified capacity factor for its generating units under its Emergency FPPAC will not be approved by the NMPRC,

• The risk that PNM may not be able to recover a portion of the increased costs of rights-of-way renewals on Native American lands through rates charged to transmission customers,

• Conditions affecting the Company’s ability to access the financial markets, including disruptions in the credit markets and actions by ratings agencies affecting the Company’s credit ratings,

• 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 on the trust funds maintained to provide nuclear decommissioning funding and pension and other postretirement benefits, including the levels of funding and expense,

• The impacts of the true-up of the purchase price for the sale of First Choice to the actual amounts of certain components of working capital at closing,

• Uncertainties surrounding the successful completion of PNMR's tender offer to repurchase up to $50.0 million of its outstanding 9.25% senior unsecured notes, due in 2015,

• Changes in ERCOT protocols,Collections experience,

• Fluctuations in interest rates,

• Weather,

• Water supply,

• Changes in fuel costs,

• Availability of fuel supplies,

• The effectiveness of risk management and commodity risk transactions,

• Seasonality and other changes in supply and demand in the market for electric power,

• The impact of mandatory energy efficiency measures on customer energy usage,

• Variability of wholesale power prices and natural gas prices,

• Volatility and liquidity in the wholesale power markets and the natural gas markets,

• Uncertainty regarding the ongoing validity of government programs for emission allowances,

• Changes in the competitive environment in the electric industry,

• The outcome of legal proceedings,

• The extent of insurance coverage available for claims made in litigation, and

• Changes in applicable accounting principles.

Any material changes to risk factors occurring after the filing of PNMR’s, PNM’s, and TNMP’s 2010 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.

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WEB SITE

The PNMR website, www.pnmresources.com, is an important source of Company information and PNMR encourages investors, analysts, and other interested parties to visit the website frequently. PNMR keeps the site updated and routinely posts new or updated information for public access. PNMR encourages analysts, investors, and other interested parties to register on the website to automatically receive Company information by e-mail. Once registered, participants can choose from a menu to automatically receive information, including 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.

PNMR’s Internet address is http://www.pnmresources.com; PNM’s Internet address is http://www.pnm.com; TNMP’s Internet address is http://www.tnpe.com. The contents of these websites are not a part of this Form 10-Q. The filings of PNMR, PNM, and TNMP with the SEC, 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 Securities and Exchange Act of 1934, are accessible free of charge at http://www.pnmresources.com as soon as reasonably practicable after they are filed with, or furnished to, the SEC. These reports are also available upon request in print from PNMR free of charge. Additionally, PNMR's Corporate Governance Principles, code of ethics (Do the Right Thing-Principles of Business Conduct), and charters of its Audit and Ethics Committee, Nominating and Governance Committee, Compensation and Human Resources Committee, and Finance Committeeare available at http://www.pnmresources.com/investors/governance.cfm and such information is available in print, without charge, to any shareholder who requests it. 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) at this location on its website.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company controls the scope of its various forms of risk through a comprehensive set of policies and procedures and oversight by senior level management and the Board. The Board’s Finance Committee sets the risk limit parameters. The RMC, comprised of corporate and business segment officers, oversees all of the risk management activities, which include commodity risk, credit risk, interest rate risk, and business risk. The RMC has oversight for the ongoing evaluation of the adequacy of the risk control organization and policies. The Company has risk control organizations, which are 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; authority to approve the types of derivatives entered into; authority to establish a general policy 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; authority to approve and open brokerage and counterparty accounts for derivatives; review of hedging and risk activities; the extent and type of reporting to be performed for monitoring of limits and positions; and quarterly reporting to the Audit and Finance Committees on these activities. The RMC also proposes risk limits, such as VaR and GEaR, to the Finance Committee for its approval.

It is the responsibility of each business segment to create its own control procedures and policies within the parameters established by the Corporate Financial Risk Management Policy, approved by the Finance Committee. The RMC reviews and approves these policies, which are created with the assistance of the Risk Management Department and the Vice President and Treasurer. Each business segment’s policies address the following controls: authorized instruments and markets; authorized personnel; policies on segregation of duties; policies on mark-to-market accounting; responsibilities for deal capture; confirmation responsibilities; responsibilities for reporting results; statement on the role of derivative transactions; and limits on individual transaction size (nominal value).

To the extent an open position exists, fluctuating commodity prices 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.

Information concerning accounting for derivatives and the risks associated with commodity contracts is set forth in Note 4. Note 4 also contains a summary of the fair values of mark-to-market energy related derivative contracts included in the Condensed Consolidated Balance Sheets.

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The following table details the changes in PNMR’s net asset or liability balance sheet position for mark-to-market energy transactions other than cash flow hedges:

	Trading		Economic Hedges			Total
Nine Months Ended September 30, 2011	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	—	$	(22,975	)	$	(22,975	)
Amount realized on contracts delivered during period	—		4,407			4,407
Changes in fair value	—		1,462			1,462
Net change recorded as mark-to-market	—		5,869			5,869
Net change recorded as regulatory    assets and liabilities	—		(140		)	(140		)
Unearned/prepaid option premiums	—		904			904
Settlement of de-designated cash flow hedges	—		183			183
Net fair value at end of period	$	—	$	(16,159	)	$	(16,159	)

	Trading			Economic Hedges			Total
Nine Months Ended September 30, 2010	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	1,239		$	2,217		$	3,456
Amount realized on contracts delivered during period	(894		)	12,837			11,943
Changes in fair value	(3		)	(53,589		)	(53,592		)
Net change recorded as mark-to-market	(897		)	(40,752		)	(41,649		)
Net change recorded as regulatory liability	—			931			931
Unearned/prepaid option premiums	—			334			334
Settlement of de-designated cash flow hedges	—			1,929			1,929
Net fair value at end of period	$	342		$	(35,341	)	$	(34,999	)

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

Fair Value of Mark-to-Market Instruments at September 30, 2011

	Less than 1 Year			1-3 Years			4+ Years			Total
				(In thousands)
Economic hedges
Prices actively quoted	$	(16,227	)	$	(5,758	)	$	—		$	(21,985	)
Prices provided by other external sources	6,682			(1,180		)	(614		)	4,888
Prices based on models and other valuations	695			243			—			938
Total	$	(8,850	)	$	(6,695	)	$	(614	)	$	(16,159	)

Risk Management Activities

PNM measures the market risk of its long-term contracts and wholesale activities using a VaR calculation to measure price movements. The VaR calculation reports the possible market loss for the respective transactions. This calculation is based on the transaction’s fair market value on the reporting date. Accordingly, the VaR calculation is not a measure of the potential accounting

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mark-to-market loss. PNM utilizes the Monte Carlo VaR simulation model. The Monte Carlo model utilizes a random generated simulation based on historical volatility to generate portfolio values. The quantitative risk information, however, is limited by the parameters established in creating the model. 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. The VaR methodology employs the following critical parameters: historical volatility estimates, market values of all contractual commitments, appropriate market-oriented holding periods, and seasonally adjusted and cross-commodity correlation estimates. The VaR calculation considers PNM’s forward positions, if any. PNM uses a holding period of three days as the estimate of the length of time that will be needed to liquidate the positions. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. The VaR confidence level established is 95%. For example, if VaR is calculated at $10.0 million, it is estimated that in 950 out of 1,000 market simulations the pre-tax loss in liquidating the portfolio would not exceed $10.0 million in the three days that it would take to liquidate the portfolio.

PNM measures VaR for all transactions that are not directly asset-related and have economic risk. PNM did not have any non-asset backed transactions for the nine months ended September 30, 2011 and 2010.

First Choice measures the market risk of its retail sales commitments and supply sourcing activities using a GEaR calculation to monitor potential risk exposures related to taking contracts to settlement and a VaR calculation to measure short-term market price impacts.

Because of its obligation to serve customers, First Choice must take certain contracts to settlement. Accordingly, a measure that evaluates the settlement of First Choice’s positions against earnings provides management with a useful tool to manage its portfolio. First Choice uses a hold-to-maturity at risk for 12 months calculation for its GEaR measurement. The calculation utilizes the same Monte Carlo simulation approach described above at a 95% confidence level and includes the retail load and supply portfolios. Management believes the GEaR results are a reasonable approximation of the potential variability of earnings against forecasted earnings. The quantitative risk information, however, is limited by the parameters established in creating the model. 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. The GEaR calculation considers First Choice’s forward position for the next 12 months and holds each position to settlement. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. For example, if GEaR is calculated at $10.0 million, it is estimated that in 950 out of 1,000 market scenarios calculated by the model the losses against the Company’s forecasted earnings over the next twelve months would not exceed $10.0 million.

For the nine months ended September 30, 2011, the average GEaR amount was $2.6 million, with high and low GEaR amounts for the period of $4.6 million and $1.3 million. The total GEaR amount at September 30, 2011 was $1.5 million. For the nine months ended September 30, 2010, the average GEaR amount for these transactions was $3.6 million, with high and low GEaR amounts for the period of $6.8 million and $1.5 million.

First Choice utilizes a VaR measure to manage its market risk. The VaR limit is based on the same total portfolio approach as the GEaR measure; however, the VaR measure is intended to capture the effects of changes in market prices over a holding period, which through June 30, 2010 was ten days. This holding period was considered appropriate given the nature of First Choice’s supply portfolio and the constraints faced by First Choice in the ERCOT market. In July 2010, First Choice modified the method of calculating VaR to consider First Choice’s positions over the life of the total portfolio and is intended to capture the effects of changes in market prices over a three day holding period. These changes, which did not significantly impact the VaR amounts, are considered appropriate given the nature of First Choice’s supply portfolio and the developing ERCOT market. The VaR calculations utilize the same Monte Carlo simulation approach described above at a 95% confidence level. The VaR amount for these transactions was $0.3 million at September 30, 2011. For the nine months ended September 30, 2011, the high, low and average VaR amounts were $1.1 million, less than $0.1 million and $0.4 million. For the nine months ended September 30, 2010, the high, low and average VaR amounts were $2.3 million, $0.1 million and $0.8 million.

The Company's risk measures are regularly monitored by the Company's RMC. The RMC has put in place procedures to ensure that increases in risk measures that exceed the prescribed limits are reviewed and, if deemed necessary, acted upon to reduce exposures. VaR or GEaR limits were not exceeded during the nine months ended September 30, 2011 or 2010.

The VaR and GEaR limits 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

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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 conducts counterparty risk analysis across business segments and uses a credit management process to assess the financial conditions of counterparties. Credit exposure is regularly monitored by the RMC. The RMC has put procedures in place to ensure that increases in credit risk that exceed the prescribed limits are reviewed and, if deemed necessary, acted upon to reduce exposures.

The following table provides information related to PNMR’s credit exposure as of September 30, 2011. The table further delineates that exposure by the credit worthiness (credit rating) of the counterparties and provides guidance as to the concentration of credit risk to individual counterparties. All credit exposures at September 30, 2011 will mature in less than two years.

Schedule of Credit Risk Exposure

September 30, 2011

Rating (1)	Credit Risk Exposure(2)		Number of Counter-parties >10%	Net Exposure of Counter-parties >10%
	(Dollars in thousands)
External ratings:
Investment grade	$	9,841	3	$	3,619
Non-investment grade	9		—	—
Internal ratings:
Investment grade	—		—	—
Non-investment grade	142		—	—
Total	$	9,992		$	3,619

(1) The Rating included in “Investment Grade” is for counterparties with a minimum S&P rating of BBB- or Moody's rating of Baa3. If the counterparty has provided a guarantee by a higher rated entity (e.g., its parent), determination is based on the rating of its guarantor. 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 full requirements 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 (pursuant to contract terms). Gross exposures can be offset according to legally enforceable netting arrangements but are not reduced by available credit collateral. Credit collateral includes cash deposits, letters of credit, and parental guarantees received from counterparties. Amounts are presented before the application of such credit collateral instruments. At September 30, 2011, 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, 2011 was $1.5 million.

Interest Rate Risk

The Company has long-term debt which subjects it to the risk of loss associated with movements in market interest rates. 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 4.6% if interest rates were to decline by 50 basis points from their levels at September 30, 2011. 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. As described in Note 7, 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 November 1, 2011, PNMR had no consolidated short-term debt

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outstanding under its revolving credit facilities and local line of credit, which allow for a maximum aggregate borrowing capacity of $780.0 million. These facilities bear interest at variable rates and the Company is exposed to interest rate risk to the extent of future increases in variable interest rates.

The securities held by PNM in the NDT and in trusts for pension and other post-employment benefits had an estimated fair value of $626.0 million at September 30, 2011, of which 42.9% 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, 2011, the decrease in the fair value of the fixed-rate securities would be 5.9%, or $15.8 million. The securities held by TNMP in trusts for pension and other post-employment benefits had an estimated fair value of $66.9 million at September 30, 2011, of which 38.4% were fixed-rate debt securities that subject TNMP to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at September 30, 2011, the decrease in the fair value of the fixed-rate securities would be 7.1%, or $1.8 million.

PNM and TNMP do not directly recover or return through rates any losses or gains on the securities, including equity and alternative investments discussed below, in the trusts for nuclear decommissioning or pension and other post-employment benefits. However, the overall performance of these trusts does enter into the periodic determinations of expense and funding levels, which are factored into the rate making process to the extent applicable to regulated operations. PNM and TNMP are at risk for shortfalls in funding of obligations due to investment losses, including those from the equity market and alternatives investment risks discussed below to the extent not ultimately recovered through rates charged to customers.

Equity Market Risk

The NDT and trusts established for PNM’s pension and post-employment benefits hold certain equity securities at September 30, 2011. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 43.7% of the securities held by the various PNM trusts as of September 30, 2011. The trusts established for TNMP’s pension and post-employment benefits hold certain equity securities. These equity securities expose TNMP to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 39.8% of the securities held by the TNMP trusts as of September 30, 2011. There was a significant decline in the general price levels of marketable equity securities in late 2008 and in early 2009. The impacts of these declines were considered in the funding and expense valuations performed for 2010 and 2011, which resulted in reduced income or increased expense related to the pension plans being recorded and required increased levels of funding beginning in 2010. See Note 8.

Alternatives Investment Risk

The Company has a current target of investing 17% of its pension assets in the alternatives asset class, which amounted to 20.9% as of September 30, 2011. This includes real estate, private equity, and hedge funds. These investments are limited partner structures that are multi-manager multi-strategy funds. This investment approach gives broad diversification and minimizes risk compared to a direct investment in any one component of the funds. The general partner oversees the selection and monitoring of the underlying managers. The Company’s Corporate Investment Committee, assisted by its investment consultant, monitors the performance of the funds and general partner’s investment process. There is risk associated with these funds due to the nature of the strategies and techniques and the use of investments that do not have readily determinable fair value. The valuation of the alternative asset class was also impacted by the significant decline in the general price levels of marketable equity securities in 2008 and 2009.

ITEM 4. CONTROLS AND PROCEDURES

PNMR

Evaluation of disclosure controls and procedures

As of the end of the period covered by this quarterly report, PNMR conducted an evaluation under the supervision and with the participation of PNMR’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.

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Changes in internal controls

There have been no changes in PNMR’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, PNMR’s internal control over financial reporting.

PNM

Evaluation of disclosure controls and procedures

As of the end of the period covered by this quarterly report, PNM conducted an evaluation under the supervision and with the participation of PNM’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.

Changes in internal controls

There have been no changes in PNM’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, PNM’s internal control over financial reporting.

TNMP

Evaluation of disclosure controls and procedures

As of the end of the period covered by this quarterly report, TNMP conducted an evaluation under the supervision and with the participation of TNMP’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.

Changes in internal controls

There have been no changes in TNMP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, TNMP’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Notes 9 and 10 in the Notes to Condensed Consolidated Financial Statements for information related to the following matters, for PNMR, PNM, and TNMP, incorporated in this item by reference.

• Regional Haze – SJGS

• Regional Haze – Four Corners

• Citizen Suit Under the Clean Air Act

• Navajo Nation Environmental Issues

• Four Corners New Source Review

• Santa Fe Generating Station

• Coal Combustion Waste Disposal – Sierra Club Allegations

• Gila River Indian Reservation Superfund Site

• PVNGS Water Supply Litigation

• San Juan River Adjudication

• Begay v. PNM et al

• Transmission Issues

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• PNM – Emergency FPPAC

• PNM – Renewable Portfolio Standard

• PNM – 2010 Electric Rate Case

• PNM – Transmission Rate Case

• PNM – Firm Requirements Rate Case

• TNMP Competitive Transition Charge True-Up Proceeding

• TNMP – Interest Rate Compliance Tariff

• TNMP – Advance Meter System Deployment and Surcharge Request

• TNMP – Remand of ERCOT Transmission Rates for 1999 and 2000

See also Climate Change Issues under Other Issues Facing the Company in MD&A. The third, fourth, and fifth paragraphs under State and Regional Activity are 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, 2010, except as discussed below.

Risk Factors concerning credit facilities expiring in 2012

The Risk Factors discussed in PNMR's Annual Report on Form 10-K contain descriptions of various risks associated with the PNMR Facility and the PNM Facility, both of which were scheduled to expire in August 2012. As discussed in Note 7, on October 31, 2011, PNMR entered into the PNMR Revolving Credit Facility, which has a financing capacity of $300.0 million, and PNM entered into the PNM Revolving Credit Facility, which has a financing capacity of $400.0 million. These new facilities replaced the PNMR Facility and the PNM Facility and expire on October 31, 2016, and include two one-year extension options, subject to approval by a majority of the lenders and, with respect to the PNM Revolving Credit Facility, regulatory approval. Entering into the new credit facilities results in the removal of the Risk Factors associated with the need to renegotitate the prior credit facilities.

Risk Factors concerning First Choice and Optim Energy

The Risk Factors discussed in PNMR's Annual Report on Form 10-K contain descriptions of various risks associated with First Choice and Optim Energy. As discussed in Note 16, PNMR entered into an agreement for the sale of First Choice to Direct LP, Inc. on September 23, 2011 that was completed on November 1, 2011. As discussed in Note 11, PNMR entered into agreements on September 23, 2011 whereby Optim Energy was restructured, which resulted in PNMR's ownership in Optim Energy being reduced from 50% to 1%. These arrangements result in the removal of the Risk Factors associated with First Choice and Optim Energy.

As a result of the March 2011 earthquake and tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, there may be additional regulations or other changes that would affect PVNGS.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  Events impacting the industry may lead the NRC to impose additional requirements and regulations on existing and new facilities.  As a result of the March 2011 earthquake and tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, various industry organizations are working to analyze information from the Japan incident and develop action plans for U.S. nuclear power plants.  Additionally, the NRC is performing its own independent review of the events at Fukushima Daiichi, including a review of the agency's processes and regulations in order to determine whether the agency should promulgate additional regulations and possibly make more fundamental changes to the NRC's system of regulation.  PNM cannot predict when the NRC will take formal action as a result of its review.  The financial and/or operational impacts on PVNGS may be significant.

            In the event of noncompliance with its requirements, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime that could ultimately result in the shut down of a unit, or both, depending upon the NRC's assessment of the severity of the situation, until compliance is achieved.  The increased costs resulting from penalties, a heightened level of scrutiny and implementation of plans to achieve compliance with NRC requirements may adversely affect the financial condition, results of operations and cash flows of PNMR and PNM.

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PNMR, PNM, and TNMP are subject to information security risks and risks of unauthorized access to their systems.

In the regular course of our utilities' businesses, the utilities handle a range of sensitive security and customer information. PNM and TNMP are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of the utilities' information systems such as theft or the inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on the operations and financial condition of PNMR, PNM, and TNMP.

PNM and TNMP operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  Despite implementation of security measures, the technology systems are vulnerable to disability, failures, or unauthorized access.  Such failures or breaches of the systems could impact the reliability of PNM's generation and PNM's and TNMP's transmission and distribution systems and also subject PNMR, PNM, and TNMP to financial harm.  If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on the operations and financial condition of PNMR, PNM, and TNMP.

ITEM 5. OTHER INFORMATION

In lieu of filing a Form 8-K under Item 2.01, PNMR is providing the following disclosure. On November 1, 2011, PNMR successfully completed its previously announced sale of First Choice to Direct LP, Inc. for $270 million in cash, plus estimated working capital of $59.3 million, which is subject to further adjustment following closing. There are no material relationships between PNMR and Direct LP, Inc., other than in respect of the transactions described herein.

In lieu of filing a Form 8-K under Item 9.01(b), PNMR is providing the unaudited pro forma consolidated statements of operations of PNMR for the nine months ended September 30, 2011 and the year ended December 31, 2010, and unaudited pro forma consolidated balance sheet of PNMR dated as of September 30, 2011, which give effect to the sale of First Choice, which are included as Exhibit 99.1 hereto.

In lieu of filing a Form 8-K under Item 5.02, PNMR is providing the following disclosure. On November 1, 2011, PNMR successfully completed the sale of First Choice, its competitive retail electric business in Texas, as described above.  On  November 2, 2011, the independent members of the Board awarded discretionary cash bonuses to PNMR's named executive officers in connection with the successful transaction.  The discretionary cash bonuses were as follows:  P.K. Collawn, President and Chief Executive Officer, $125,000; C.E. Eldred, Executive Vice President and Chief Financial Officer, $100,000;  P.V. Apodaca, Senior Vice President, General Counsel and Secretary, $75,000;  A.A. Cobb, Senior Vice President and Chief Administrative Officer, $25,000; and T.G. Sategna, Vice President and Corporate Controller, $25,000.

ITEM 6. EXHIBITS

3.1	PNMR	Articles of Incorporation of PNM Resources, 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 the Company’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 the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
3.4	PNMR	Bylaws of PNM Resources, Inc. 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 the Company’s Report on Form 10-Q for the fiscal quarter ended June 30, 2002)
3.6	TNMP	Bylaws of TNMP, as amended effective June 26, 2011*
12.1	PNMR	Ratio of Earnings to Fixed Charges

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12.2	PNMR	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
12.3	PNM	Ratio of Earnings to Fixed Charges
12.4	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
99.1	PNMR	Unaudited pro forma consolidated statements of operations of PNMR for the nine months ended September 30, 2011 and the year ended December 31, 2010, and unaudited pro forma consolidated balance sheet of PNMR as of September 30, 2011, which give effect to the sale of First Choice
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

* The TNMP by-laws were amended to allow for the President and Chief Executive Officer to be different individuals.

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SIGNATURE

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

		PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO TEXAS-NEW MEXICO POWER COMPANY
		(Registrants)
Date:	November 3, 2011	/s/ Thomas G. Sategna
		Thomas G. Sategna
		Vice President and Corporate Controller
		(Officer duly authorized to sign this report)

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EX-3.6

Exhibit 3.6

BYLAWS

TEXAS-NEW MEXICO POWER COMPANY

As Amended on June 26, 2011

BYLAWS

OF

TEXAS-NEW MEXICO POWER COMPANY

ARTICLE I

MEETINGS OF SHAREHOLDERS

SECTION 1.     MEETINGS

The annual meeting of shareholders shall be held at the time and place set by resolution of the Board of Directors for the election of directors and the transaction of such other business as may properly come before the meeting.

Special meetings may be called by a majority of the Board of Directors, the Chairman of the Board, the President or by holders of not less than one-tenth of all the shares entitled to vote at the meeting.

SECTION 2.     NOTICE

Written notice of any meeting stating the time and place, and if a special meeting, the purpose, of the meeting shall be mailed to each shareholder of record entitled to vote at the meeting at the address of the shareholder as it appears on the stock transfer books of the Corporation, except as otherwise provided by law. Notices of any shareholder meetings shall be mailed not less than thirty (30) days before the meeting.

SECTION 3.     ADJOURNMENT

Whenever a quorum is not present at any meeting of the shareholders, or whenever it may be deemed desirable, a majority in interest of the shareholders present in person or by proxy may adjourn the meeting from time to time to any future date, without notice other than by announcement at the meeting. At any continuation of the adjourned meeting at which a quorum

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is present, any business may be transacted which might have been transacted at the meeting originally scheduled.

SECTION 4.     ORDER OF BUSINESS

(a) The Chairman of the Board, or in the absence of the Chairman, the President, or in their absence, a director designated by the Board of Directors, shall call meetings of the shareholders to order and shall act as Chairman of the meeting. The shareholders may appoint any shareholder or the proxy of any shareholder to act as Chairman of any meeting of the shareholders in the absence of the Chairman of the Board, President and a director designated by the Board to serve as Chairman of the meeting. The Secretary, or in the absence of the Secretary, an Assistant Secretary, shall act as Secretary at all meetings of the shareholders, but in the absence of the Secretary and Assistant Secretary at any meetings of the shareholders, the Chairman of the meeting may appoint any person to act as Secretary of the meeting.

(b) The Chairman of the meeting shall have the right to determine the order of business at the meeting, to prescribe the rules and procedures for the conduct of the meeting, and to do all things necessary or desirable for the proper conduct of the meeting.

SECTION 5.     VOTING

At meetings of shareholders, every shareholder having voting rights as provided for in the Articles of Incorporation shall be entitled to one (1) vote for each share of stock outstanding in the name of the shareholder on the books of the Corporation on the date on which shareholders entitled to vote are determined or as otherwise provided for in the Articles of Incorporation. Each shareholder may be represented and vote by a proxy or proxies appointed by an instrument in writing or other manner authorized by the Board of Directors to the extent permitted by law. If the instrument designates two (2) or more persons to act as proxies, a majority of the proxies

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present at the meeting may exercise all of the powers conferred by the instrument unless the instrument provides otherwise. No proxy shall be voted at any meeting or continuation of an adjourned meeting other than that for which the proxy is given.

In all elections for directors, voting may be by written ballot.

The Board of Directors may fix a date in advance not exceeding thirty (30) days before the date of any meeting of shareholders as a record date for the determination of shareholders entitled to notice of and to vote at the meeting. Only shareholders of record on the date so fixed shall be entitled to notice of and to vote at the meeting.

ARTICLE II

DIRECTORS

SECTION 1.     NUMBER AND TERMS

The business and property of the Corporation shall be managed under the direction of the Board of Directors. The shareholders shall fix the number of directors, which shall be no less than three (3) and no more than twelve (12).

SECTION 2.     CHAIRMAN OF THE BOARD OF DIRECTORS

The Chairman of the Board shall be elected annually by the shareholders at the annual meeting and shall hold that office until a successor is elected and qualified. In the event of the incapacity of the Chairman of the Board, the shareholders shall designate an Acting Chairman who shall, during the incapacity of the Chairman of the Board, assume and perform all functions and duties which the Chairman of the Board is authorized or required by law to do. The Chairman of the Board shall have the power to call special meetings of the shareholders and of the directors for any purpose. The Chairman of the Board shall preside at all meetings of the shareholders and of the Board of Directors unless the Chairman of the Board is absent or

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incapacitated. The Chairman of the Board, subject to the authority of the Board of Directors, shall generally do and perform all acts incident to the position of the Chairman of the Board and which are authorized or required by law.

SECTION 3.     COMPENSATION

Directors shall receive compensation for their services as directors as may be fixed by the holders of Common Stock, including reimbursement for expenses for Board related services.

SECTION 4.     MEETINGS

The meetings of the Board of Directors shall be held at the times and places designated by the Board of Directors. The annual meeting of the Board of Directors for the election of officers and such other business as may properly come before the meeting shall be held immediately following the annual meeting of shareholders. Special meetings of the Board of Directors shall be held whenever called at the direction of the Chairman of the Board, the President, or any three (3) directors.

SECTION 5.     NOTICE

No notice shall be required of any annual or regular meeting of the Board of Directors unless the place has been changed from that last designated by the Board of Directors. Notice of any annual or regular meeting, when required, or of any special meeting of the Board of Directors shall be given to each director in writing or by telephone at least twenty-four (24) hours before the time fixed for the meeting. Notice may be waived by any director. Unless otherwise indicated in the notice, any and all business may be transacted at a special meeting. At any meeting at which every director is present, even without notice, any business may be transacted.

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SECTION 6.     ADJOURNMENTS

Any annual, regular or special meeting of the Board of Directors may be adjourned from time to time by the members present whether or not a quorum is present, and no notice shall be required of any continuation of an adjourned meeting beyond the announcement at the adjourned meeting.

SECTION 7.     INDEMNIFICATION

Each person serving as a director or an officer of the Corporation, or, at the request of the Corporation, as a director or an officer of any other company in which the Corporation has a financial interest and regardless of whether or not the person is then in office, and the heirs, executors, administrators and personal representatives of the person, shall be indemnified by the Corporation to the full extent of the authority of the Corporation to so indemnify as authorized by Texas law.

SECTION 8.    COMMITTEES

The Board of Directors may designate from among its members one (1) or more committees, to exercise the power and authority and perform the functions that the Board may determine, except as may be limited by law.

ARTICLE III

CONTRACTS AND NEGOTIABLE INSTRUMENTS

SECTION 1.     AUTHORITY TO SIGN CONTRACTS

Unless the Board of Directors shall otherwise specifically direct, all contracts, instruments, documents or agreements of the Corporation shall be executed in the name of the Corporation by the President, or any Vice President, or any other employee, if approved by the

5

President by either administrative policy letter or specific written designation. It shall not be necessary that the corporate seal be affixed to any contract.

SECTION 2.     AUTHORITY TO SIGN NEGOTIABLE INSTRUMENTS

Except as otherwise authorized by the Board of Directors, all checks, drafts, bills of exchange, promissory notes, electronic funds transfer documents, and other negotiable instruments shall be signed by the President, any Vice President, Secretary or Treasurer. Facsimile signatures shall be sufficient to meet the requirements of this section.

SECTION 3.     APPROVAL BY SHAREHOLDERS

The Board of Directors in its discretion may submit any contract, or act, for approval or ratification at any annual meeting of the shareholders, or at any special meeting of the shareholders called for the purpose of considering the act or contract. Any contract or act that is approved or ratified by the vote of the holders of the Common Stock of the Corporation which is represented in person or by proxy at the meeting shall be valid and binding upon the Corporation.

ARTICLE IV

OFFICERS

SECTION 1. NUMBER, ELECTION AND TERM

The officers of the Corporation shall be a President, one or more Vice Presidents, a Secretary, a Treasurer, and a Controller, who shall be elected annually by the Board of Directors at the annual meeting and who shall hold office until the next annual meeting or until a successor is elected and qualified except for the President who shall be elected as provided for in Section 2 below. The Board of Directors may designate one or more Vice Presidents as "Executive" Vice Presidents and one or more Vice Presidents as "Senior" Vice Presidents. The title of any Vice President may include words indicative of the area of responsibility of the Vice President. The

6

Board of Directors shall designate one of the Vice Presidents as the chief financial officer of the Corporation. The Board of Directors may from time to time appoint such additional officers as the interest of the Corporation may require and fix their terms and duties of office. A vacancy occurring in any office of a Vice President may be filled by the Board of Directors. All Vice Presidents shall hold office at the discretion of the Board of Directors and shall be subject to removal at any time by the affirmative vote of a majority of the whole Board of Directors. Election of any person as an officer of the Corporation shall not of itself create contract rights. The Board may appoint as officers persons who are not employees of the Corporation, with the consent of the shareholders.

SECTION 2. PRESIDENT

The President shall be elected annually by the shareholders at the annual meeting of shareholders and shall serve until a successor is elected and qualified. The President shall provide active management over all operations of the Corporation subject to control of the Board of Directors. The President shall have the power to appoint and discharge, subject to the general approval or review by the Board of Directors, employees and agents of the Corporation and to fix their compensation, to make and sign contracts and agreements in the name of and on behalf of the Corporation and direct the general management and control of the business and affairs of the Corporation. The President may delegate authority to officers of the Corporation as the President may determine. The President shall have the power to segregate the operations of the Corporation into areas of responsibility. The President shall see that the books, reports, statements and certificates required by law are properly kept, made, and filed, and shall generally do and perform all acts which are authorized or required by law. The President shall designate a Vice President who shall, during the absence or incapacity of the President, assume and perform

7

all functions and duties which the President might lawfully do if present in person and not under any incapacity.

SECTION 3. VICE PRESIDENTS

Each Vice President designated as "Executive" or "Senior Vice President" shall be responsible for the areas and activities assigned by the President, shall be subject to the authority of the President and shall assist in the general control and management of the business and affairs of the Corporation.

All other Vice Presidents shall be responsible for the areas and activities assigned by the President and shall perform other duties as may be required, including those assigned to an Executive or Senior Vice President during the absence or incapacity of the Executive or Senior Vice President.

SECTION 4. SECRETARY

The Secretary shall keep a record in the proper books provided for that purpose of meetings and proceedings of shareholders, the Board of Directors and Committees of the Board of Directors, and shall record all votes of the directors and shareholders in a book to be kept for that purpose. The Secretary shall notify the directors and shareholders of meetings as required by law or by the bylaws of the Corporation and shall perform other duties as may be required by law or the bylaws of the Corporation, or which may be assigned from time to time by the Board of Directors, Chairman of the Board or President. The Secretary is authorized to appoint one or more assistants from time to time as the Secretary deems advisable, the assistant or assistants to serve at the pleasure of the Secretary, andto perform the duties that are delegated by the Secretary. An assistant shall not be an officer of the Corporation.

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SECTION 5. TREASURER

The Treasurer shall have the custody of all the funds and securities of the Corporation, and shall have the power on behalf of the Corporation to sign checks, notes, drafts and other evidences of indebtedness, to borrow money for the current needs of the business of the Corporation and to make short‑term investments of surplus funds of the Corporation. The Treasurer shall render to the Board of Directors, the Chairman of the Board or the President, whenever requested, an account of all transactions performed as Treasurer and of the financial condition of the Corporation. The Treasurer shall perform other duties as may be assigned by the Board of Directors, the Chairman of the Board or the President. The Treasurer is authorized to appoint one or more assistants from time to time as the Treasurer deems advisable, the assistant or assistants to serve at the pleasure of the Treasurer, and to perform the duties that are delegated by the Treasurer. An assistant shall not be an officer of the Corporation.

SECTION 6. CONTROLLER

The Controller shall be the chief accounting officer of the Corporation and have full responsibility and control of the accounting practices of the Corporation The Controller shall, subject to the approval of the Board of Directors or the President, establish accounting policies. The Controller shall standardize and coordinate accounting practices, supervise all accounting records and the presentation of all financial statements and tax returns. The Controller shall have other powers and duties as, from time to time, may be conferred by the Board of Directors, the Chairman of the Board or the President. The Controller is authorized to appoint one or more assistants from time to time as the Controller deems advisable, the assistant or assistants to serve at the pleasure of the Controller, and to perform the duties that are delegated by the Controller. An assistant shall not be an officer of the Corporation.

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SECTION 7.    FORM OF APPOINTMENT

In making any appointments of assistants, the Secretary, Treasurer and Controller shall use the following form:

I, ________________ (Name), the duly elected ______________ (Title) of Texas-New Mexico Power Company do hereby appoint(Name) to serve as Assistant __________________(Title) for the period of (Date) to (Date), unless this appointment is terminated earlier in writing, to assume or perform all functions and duties which I might require and, in my absence or incapacity, which I might lawfully do if present and not under any incapacity.

Any appointments of assistants by the Secretary, Treasurer or Controller and any terminations of appointments shall be maintained in the records of the Secretary's office.

ARTICLE V

CAPITAL STOCK

SECTION 1.    CERTIFICATES OF STOCK

The name of the person owning shares of the capital stock of the Corporation, together with the number of shares and the date of issue, shall be entered on the Corporation's books. All certificates surrendered to the Corporation shall be canceled, and no new certificates shall be issued until a certificate or certificates aggregating the same number of shares of the same class have been surrendered or canceled. The Board of Directors may make proper provision, from time to time, for the issuance of new certificates in place of lost, destroyed or stolencertificates.

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SECTION 2.    TRANSFER OF SHARES

Transfers of shares shall be made only upon the books of the Corporation by the holderor by the holder's attorney in fact upon surrender of certificates for a like number of shares.

SECTION 3.    LOST, DESTROYED OR STOLEN CERTIFICATES

A new certificate of stock may be issued in the place of any certificate previously issued by the Corporation, or any predecessor of the Corporation, alleged to have been lost, destroyed or stolen. The Board of Directors may, in its discretion, require the owner of the lost, destroyed or stolen certificate to give to the Corporation satisfactory evidence that the certificate was lost, destroyed or stolen.

SECTION 4.    FIXING OF RECORD DATES

For the purpose of determining shareholders entitled to notice of any meeting of shareholders, or entitled to receive payment of any dividend, or in order to make a determination of shareholders for any other proper purpose, the Board of Directors may, by resolution, provide that the stock transfer books be closed for a stated period not to exceed thirty (30) days. If the stock transfer books are closed for the purpose of determining shareholders entitled to notice of a meeting of shareholders, the books shall be closed for at least ten (10) days immediately prior to the meeting.

In lieu of closing the stock transfer books, the Board of Directors may, by resolution, fix in advance a date as the record date for any determination of shareholders, the date to be not more than thirty (30)days and, in case of a meeting of shareholders, not less than ten (10)days prior to the date on which the action requiring the determination of shareholders is to be taken.

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ARTICLE VI

MISCELLANEOUS PROVISIONS

SECTION 1.    BOOKS

The books of the Corporation, except as otherwise provided by law, may be kept outside of the State of Texas, at such place or places as may be designated by the Board of Directors.

SECTION 2.    CORPORATE SEAL

The common corporate seal is, and until otherwise ordered by the Board of Directors shall be, an impression circular in form upon paper or wax bearing the words “Texas-New Mexico Power Company.” The seal shall be in the charge of the Secretary. If and when directed by the Board of Directors, a duplicate of the seal may be kept and used by the Treasurer or by an Assistant Secretary or Assistant Treasurer.

SECTION 3.    FISCAL YEAR

The fiscal year of the Corporation shall be as determined by the Board of Directors.

SECTION 4.    PRINCIPAL OFFICE

The principal office shall be established and maintained at a place designated by the Board of Directors.

SECTION 5.    BYLAWS

The common shareholders of the Corporation are authorized to alter, amend and repeal the Corporation's Bylaws, or adopt new Bylaws. The Board of Directors of the Corporation is authorized to alter, amend and repeal the Corporation's Bylaws, except as provided in this Section.

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The Board of Directors is not authorized to alter, amend or repeal the provisions of the Corporation's Bylaws relating to the number of directors, compensation of directors, selection of the Chairman of the Board of Directors, and selection of the President.

13

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, 2011					2010				2009			2008				2007			2006
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized		$	90,970			$	123,633			$	123,833		$	134,958			$	124,299		$	135,819
Amortization of debt premium, discount and expenses		2,741				4,627				5,430			6,386				6,566			4,729
Interest from discontinued operations (including capitalized interest)		—				—				1,027			13,758				12,546			11,790
Estimated interest factor of lease rental charges		5,130				6,888				7,034			7,894				8,804			7,124
Preferred dividend requirements of subsidiary		591				1,075				759			689				556			798
Total Fixed Charges		$	99,432			$	136,223			$	138,083		$	163,685			$	152,771		$	160,260
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest		$	112,732			$	(63,379	)		$	94,751		$	(388,381	)		$	63,112		$	164,018
(Earnings) loss of equity investee		—				15,223				30,145			29,687				(7,581		)	—
Earnings (loss) from continuing operations before income taxes, non-controlling interest, and investee earnings		112,732				(48,156		)		124,896			(358,694		)		55,531			164,018
Fixed charges as above		99,432				136,223				138,083			163,685				152,771			160,260
Interest capitalized		(1,886		)		(3,401		)		(7,743		)	(8,849		)		(10,740		)	(6,503		)
Non-controlling interest in earnings of Valencia		(10,764		)		(13,563		)		(11,890		)	(7,179		)		—			—
Preferred dividend requirements of subsidiary		(591		)		(1,075		)		(759		)	(689		)		(556		)	(798		)
Earnings Available for Fixed Charges		$	198,923			$	70,028			$	242,587		$	(211,726	)		$	197,006		$	316,977
Ratio of Earnings to Fixed Charges		2.00			1	0.51			2	1.76			N/M			3	1.29			1.98
1 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the nine months ended September 30, 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 2.22.
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
PNM RESOURCES, INC. AND SUBSIDIARIES
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
(In thousands, except ratio)
	Nine Months Ended				Year Ended December 31,
	September 30, 2011				2010				2009			2008				2007			2006
Combined fixed charges and preferred stock dividends, as defined by the Securities and
Exchange Commission:
Interest expensed and capitalized	$	90,970			$	123,633			$	123,833		$	134,958			$	124,299		$	135,819
Amortization of debt premium, discount and expenses	2,741				4,627				5,430			6,386				6,566			4,729
Interest from discontinued operations (including capitalized interest)	—				—				1,027			13,758				12,546			11,790
Estimated interest factor of lease rental charges	5,130				6,888				7,034			7,894				8,804			7,124
Preferred dividend requirements of subsidiary	591				1,075				759			689				556			798
Total Fixed Charges	99,432				136,223				138,083			163,685				152,771			160,260
Preferred stock dividend requirements	1,783				4,865				3,433			780				—			—
Total Combined Fixed Charges and Preferred Stock Dividends	$	101,215			$	141,088			$	141,516		$	164,465			$	152,771		$	160,260
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	112,732			$	(63,379	)		$	94,751		$	(388,381	)		$	63,112		$	164,018
(Earnings) loss of equity investee	—				15,223				30,145			29,687				(7,581		)	—
Earnings (loss) from continuing operations before income taxes, non-controlling interest, and investee earnings	112,732				(48,156		)		124,896			(358,694		)		55,531			164,018
Fixed charges as above	99,432				136,223				138,083			163,685				152,771			160,260
Interest capitalized	(1,886		)		(3,401		)		(7,743		)	(8,849		)		(10,740		)	(6,503		)
Non-controlling interest in earnings of Valencia	(10,764		)		(13,563		)		(11,890		)	(7,179		)		—			—
Preferred dividend requirements of subsidiary	(591		)		(1,075		)		(759		)	(689		)		(556		)	(798		)
Earnings Available for Combined Fixed Charges and Preferred Stock Dividends	$	198,923			$	70,028			$	242,587		$	(211,726	)		$	197,006		$	316,977
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends	1.97			1	0.50			2	1.71			N/M			3	1.29			1.98
1 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the nine months ended September 30, 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 combined fixed charges and preferred stock dividends would have been 2.18.
2 The shortfall in the earnings available for combined fixed charges and preferred stock dividends to achieve a ratio of earnings to combined fixed charges and preferred stock dividends of 1.00 amounted to $71.1 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 combined fixed charges and preferred stock dividends would have been 1.83.
3 The ratio of earnings to combined fixed charges and preferred stock dividends for the year ended December 31, 2008 is not meaningful since earnings available for combined fixed charges and preferred stock dividends is negative. The shortfall in the earnings available for combined fixed charges and preferred stock dividends to achieve a ratio of earnings to combined fixed charges and preferred stock dividends of 1.00 amounted to $376.2 million for the year ended December 31, 2008.

EX-12.3

Exhibit 12.3
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, 2011				2010			2009			2008				2007			2006
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	54,468			$	73,423		$	73,104		$	72,427			$	58,045		$	49,379
Amortization of debt premium, discount and expenses	919				1,274			1,336			4,345				4,618			2,871
Interest from discontinued operations (including capitalized interest)	—				—			1,027			13,758				12,546			11,790
Estimated interest factor of lease rental charges	3,114				4,103			4,517			4,553				4,661			4,337
Total Fixed Charges	$	58,501			$	78,800		$	79,984		$	95,083			$	79,870		$	68,377
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	78,208			$	107,288		$	45,627		$	(69,324	)		$	34,611		$	89,657
Fixed charges as above	58,501				78,800			79,984			95,083				79,870			68,377
Non-controlling interest in earnings of Valencia	(10,764		)		(13,563		)	(11,890		)	(7,179		)		—			—
Interest capitalized	(1,220		)		(2,811		)	(6,067		)	(7,363		)		(10,033		)	(5,257		)
Earnings Available for Fixed Charges	$	124,725			$	169,714		$	107,654		$	11,217			$	104,448		$	152,777
Ratio of Earnings to Fixed Charges	2.13			1	2.15			1.35			0.12			2	1.31			2.23
1 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the nine months ended September 30, 2011 includes a pre-tax loss of $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 2.43.
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-12.4

Exhibit 12.4
TEXAS-NEW MEXICO POWER COMPANY
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Nine Months Ended				Year Ended December 31,
	September 30, 2011				2010			2009			2008			2007			2006
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	20,985			$	28,632		$	25,609		$	17,861		$	23,523		$	27,374
Amortization of debt premium, discount and expenses	1,306				2,683			3,355			1,504			1,925			1,695
Estimated interest factor of lease rental charges	982				1,246			831			571			844			367
Total Fixed Charges	$	23,273			$	32,561		$	29,795		$	19,936		$	26,292		$	29,436
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes	$	27,979			$	26,026		$	20,151		$	2,335		$	29,055		$	17,905
Fixed charges as above	23,273				32,561			29,795			19,936			26,292			29,436
Interest capitalized	(411		)		(158		)	(1,144		)	(1,025		)	(332		)	(209		)
Earnings Available for Fixed Charges	$	50,841			$	58,429		$	48,802		$	21,246		$	55,015		$	47,132
Ratio of Earnings to Fixed Charges	2.18			1	1.79			1.64			1.07			2.09			1.60
1 Earnings from continuing operations before income taxes for the nine months ended September 30, 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 2.35.

EX-31.1

PNM Resources

Alvarado Square

Albuquerque, NM 87158

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 3, 2011	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			PNM Resources, Inc.

EX-31.2

PNM Resources

Alvarado Square

Albuquerque, NM 87158

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 3, 2011	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President
			Chief Financial Officer
			PNM Resources, Inc.

EX-31.3

Public Services Company of New Mexico

Alvarado Square

Albuquerque, NM 87158

EXHIBIT 31.3

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 3, 2011	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			Public Service Company of New Mexico

EX-31.4

Public Services Company of New Mexico

Alvarado Square

Albuquerque, NM 87158

EXHIBIT 31.4

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 3, 2011	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President
			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 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 3, 2011	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and 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 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 3, 2011	By:	/s/ Thomas G. Sategna
			Thomas G. Sategna
			Vice President and Controller
			Texas-New Mexico Power Company

EX-32.1

PNM Resources

Alvarado Square

Albuquerque, NM 87158

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, 2011, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on November 3, 2011 (“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 3, 2011	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 Services Company of New Mexico

Alvarado Square

Albuquerque, NM 87158

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, 2011, for Public Services Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on November 3, 2011 (“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 3, 2011	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, 2011, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on November 3, 2011 (“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 3, 2011	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and 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

EX-99.1

EXHIBIT 99.1

PNM RESOURCES, INC. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following Unaudited Pro Forma Condensed Consolidated Financial Statements of PNM Resources, Inc. (“PNMR”) as of and for the nine months ended September 30, 2011 and for the year ended December 31, 2010 are derived from and should be read in conjunction with the historical consolidated statements and related notes of PNMR.

As previously reported, on September 23, 2011, PNMR entered into an agreement for the sale of FCP Enterprises, Inc. and Subsidiaries, which are indirect wholly-owned subsidiaries of PNMR and comprise the “First Choice” business segment of PNMR, to Direct LP, Inc. for $270.0 million plus the actual amounts of certain components of working capital at the closing date. First Choice is a certified retail electric provider operating in Texas. Closing of the transaction was subject to customary conditions, including an antitrust review under the Hart-Scott-Rodino Antitrust Improvements Act, which was received on October 7, 2011. Closing occurred on November 1, 2011, with PNMR receiving $329.3 million, which includes an estimate of the components of working capital discussed above. Such amount is subject to adjustment based on the actual amounts of the components of working capital at October 31, 2011. In addition, as previously reported, PNMR entered into agreements, which reduced PNMR's ownership in Optim Energy, LLC (“Optim Energy”) from 50% to 1% on September 23, 2011.

The Unaudited Pro Forma Condensed Consolidated Balance Sheet for PNMR as of September 30, 2011 reflects the sale of First Choice as if it had occurred September 30, 2011. In addition, the Condensed Consolidated Balance Sheet reflects the use of proceeds from the sale of First Choice to repay short-term debt, including that incurred for the purchase of PNMR's outstanding Convertible Preferred Stock, Series A , as well as the October 6, 2011 sale of senior unsecured notes by Public Service Company of New Mexico, a wholly owned subsidiary of PNMR. The reduction in PNMR's ownership in Optim Energy had no impact on the Unaudited Pro Forma Condensed Consolidated Balance Sheet of PNMR as of September 30, 2011 due to PNMR fully impairing its investment in Optim Energy as of December 31, 2010.

The Unaudited Pro Forma Condensed Consolidated Statements of Earnings of PNMR for the nine months ended September 30, 2011 and the year ended December 31, 2010 reflect the sale of First Choice and the reduction in ownership in Optim Energy, as if both transactions had occurred as of January 1, 2010.

The Unaudited Pro Forma Condensed Consolidated Financial Statements have been prepared based upon currently available information and assumptions that are deemed appropriate by PNMR's management. The pro forma information is for informational purposes only and is not intended to be indicative of the actual consolidated financial position or results of operations that would have been reported had the transaction occurred on the date indicated, nor does the information represent a forecast of the financial results of PNMR for any future period.

PNM RESOURCES, INC. AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

AS OF SEPTEMBER 30, 2011

(Unaudited)

			Pro Forma Adjustments
	PNMR Historical		First Choice				Other				Pro Forma
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	22,298	$	342,986		B	$	(73,475	)	D
							(289,000		)	F
							158,331			E	$	161,140
Accounts receivable, net of uncollectible accounts	107,637		—				—				107,637
Unbilled revenues	47,793		—				—				47,793
Other receivables	46,955		—				—				46,955
Materials, supplies, and fuel stock	53,092		—				—				53,092
Regulatory assets	28,693		—				—				28,693
Commodity derivative instruments	3,716		—				—				3,716
Income taxes receivable	99,506		—				—				99,506
Current portion of accumulated deferred income taxes	886		—				—				886
Current assets of business unit held for sale	166,119		(166,119		)	A	—				—
Other current assets	49,043		—				—				49,043
Total current assets	625,738		176,867				(204,144		)		598,461
Other Property and Investments:
Investment in PVNGS lessor notes	79,390		—				—				79,390
Investments held by NDT	157,001		—				—				157,001
Other investments	14,639		—				—				14,639
Non-utility property, net of accumulated depreciation	5,139		—				—				5,139
Total other property and investments	256,169		—				—				256,169
Utility Plant:
Plant in service and plant held for future use	4,998,685		—				—				4,998,685
Less accumulated depreciation and amortization	1,686,971		—				—				1,686,971
	3,311,714		—				—				3,311,714
Construction work in progress	159,918		—				—				159,918
Nuclear fuel, net of accumulated amortization	78,218		—				—				78,218
Net utility plant	3,549,850		—				—				3,549,850
Deferred Charges and Other Assets:
Regulatory assets	475,937		—				—				475,937
Goodwill	278,297		—				—				278,297
Other intangible assets, net of accumulated amortization	—		—				—				—
Commodity derivative instruments	247		—				—				247
Non-current assets of business unit held for sale	101,059		(101,059		)	A	—				—
Other deferred charges	85,343		—				1,440			E	86,783
Total deferred charges and other assets	940,883		(101,059		)		1,440				841,264
	$	5,372,640	$	75,808			$	(202,704	)		$	5,245,744

PNM RESOURCES, INC. AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

AS OF SEPTEMBER 30, 2011

(Unaudited)

				Pro Forma Adjustments
	PNMR Historical			First Choice				Other				Pro Forma
	(in thousands, except for share information)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Short-term debt	$	289,000		$	—			$	(289,000	)	F	$	—
Current installments of long-term debt	2,252			—				—				2,252
Accounts payable	71,949			10,750			C	—				82,699
Accrued interest and taxes	82,636			—				—				82,636
Regulatory liabilities	429			—				—				429
Commodity derivative instruments	1,746			—				—				1,746
Dividends declared	10,966			—				—				10,966
Liability for purchase of Series A Preferred Stock	73,475			—				(73,475		)	D	—
Current liabilities of business unit held for sale	103,915			(103,915		)	A	—				—
Other current liabilities	76,281			—				—				76,281
Total current liabilities	712,649			(93,165		)		(362,475		)		257,009
Long-term Debt	1,564,077			—				159,771			E	1,723,848
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	582,485			81,846			C	—				664,331
Accumulated deferred investment tax credits	16,350			—				—				16,350
Regulatory liabilities	363,087			—				—				363,087
Asset retirement obligations	77,290			—				—				77,290
Accrued pension liability and postretirement benefit cost	227,401			—				—				227,401
Commodity derivative instruments	1,913			—				—				1,913
Non-current liabilities of business unit held for sale	17,596			(17,596		)	A	—				—
Other deferred credits	123,054			—				—				123,054
Total deferred credits and other liabilities	1,409,176			64,250				—				1,473,426
Total liabilities	3,685,902			(28,915		)		(202,704		)		3,454,283
Cumulative Preferred Stock of Subsidiary
without mandatory redemption requirements	11,529			—				—				11,529
Equity:
PNMR Convertible Preferred Stock Series A	—			—				—				—
PNMR common stockholders' equity:
Common stock outstanding (no par value, 120,000,000 shares authorized; issued and outstanding 86,673,174)	1,318,539			—				—				1,318,539
Accumulated other comprehensive income (loss), net of income taxes	(72,913		)	—				—				(72,913		)
Retained earnings	345,614			104,723			C	—				450,337
Total PNMR common stockholders' equity	1,591,240			104,723				—				1,695,963
Non-controlling interest in Valencia	83,969			—				—				83,969
Total equity	1,675,209			104,723				—				1,779,932
	$	5,372,640		$	75,808			$	(202,704	)		$	5,245,744

PNM RESOURCES, INC. AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF EARNINGS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011

(Unaudited)

				Pro Forma Adjustments
	PNMR Historical			First Choice				Other				Pro Forma
	(In thousands, except per share amounts)
Electric Operating Revenues	$	1,352,747		$	(405,485	)	A	$	30,608		M	$	977,870
Operating Expenses:
Cost of energy	582,814			(303,285		)	A	30,608			M	310,137
Administrative and general	197,016			(66,850		)	A	5,016			K
								3,797			J	138,979
Energy production costs	135,510			—				—				135,510
Regulatory disallowances	21,402			—				—				21,402
Depreciation and amortization	119,115			(987		)	A	—				118,128
Transmission and distribution costs	52,962			—				—				52,962
Taxes other than income taxes	50,564			(843		)	A	—				49,721
Total operating expenses	1,159,383			(371,965		)		39,421				826,839
Operating income	193,364			(33,520		)		(8,813		)		151,031
Other Income and Deductions:
Interest income	12,010			(63		)	A	—				11,947
Gains (losses) on investments held by NDT	7,688			—				—				7,688
Other income	3,559			(1		)	A	(53		)	J	3,505
Equity in net earnings (loss) of Optim Energy	—			—				—				—
Other deductions	(11,638		)	495			A	—				(11,143		)
Net other income (deductions)	11,619			431			A	(53		)		11,997
Interest charges	92,251			(535		)		(4,642		)	F
								6,551			E	93,625
Earnings before Income Taxes	112,732			(32,554		)		(10,775		)		69,403
Income taxes	37,206			(11,833		)	A	1,838			F
								(2,593		)	E
								(1,986		)	K
								(1,524		)	J	21,108
Net Earnings	75,526			(20,721		)		(6,510		)		48,295
(Earnings) Attributable to Valencia Non-controlling interest	(10,764		)	—				—				(10,764		)
Preferred Stock Dividend Requirements of Subsidiary	(396		)	—				—				(396		)
Net Earnings Attributable to PNMR	$	64,366		$	(20,721	)		$	(6,510	)		$	37,135
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.70										$	0.43
Diluted	$	0.70										$	0.43
Number of Shares Used in Calculating Earnings per Share
Basic	91,465							(4,638		)	D	86,827
Diluted	91,981							(4,638		)	D	87,343

PNM RESOURCES, INC. AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF EARNINGS

FOR THE YEAR ENDED DECEMBER 31, 2010

(Unaudited)

				Pro Forma Adjustments
	PNMR Historical			First Choice				Optim Energy			Other				Pro Forma
	(In thousands, except per share amounts)
Electric Operating Revenues	$	1,673,517		$	(483,203	)	A	$	—		$	39,084		M	$	1,229,398
Operating Expenses:
Cost of energy	700,727			(350,476		)	A	—			39,084			M	389,335
Administrative and general	264,556			(90,873		)	A	—			6,211			K
				—				—			5,923			J	185,817
Energy production costs	195,919			—				—			—				195,919
Depreciation and amortization	151,704			(864		)	A	—			—				150,840
Transmission and distribution costs	63,421			—				—			—				63,421
Taxes other than income taxes	57,738			(1,204		)	A	—			—				56,534
Total operating expenses	1,434,065			(443,417		)		—			51,218				1,041,866
Operating income	239,452			(39,786		)		—			(12,134		)		187,532
Other Income and Deductions:
Interest income	18,896			(18		)	A	—			—				18,878
Gains (losses) on investments held by NDT	4,868			—				—			—				4,868
Other income	14,837			—				—			(95		)	J	14,742
Equity in net earnings (loss) of Optim Energy	(15,223		)	—				15,223		G	—				—
Impairment of equity investment in Optim Energy	(188,176		)	—				184,263		H	—				(3,913		)
Other deductions	(12,660		)	411			A	—			—				(12,249		)
Net other income (deductions)	(177,458		)	393				199,486			(95		)		22,326
Interest charges	125,373			(1,268		)	A	—			(5,353		)	F
								—			8,734			E	127,486
Earnings (Loss) before Income Taxes	(63,379		)	(38,125		)		199,486			(15,610		)		82,372
Income taxes (Benefit)	(32,255		)	(14,064		)	A	78,977		I	2,119			F
											(3,458		)	E
											(2,459		)	K
											(2,383		)	J	26,477
Net Earnings	(31,124		)	(24,061		)		120,509			(9,429		)		55,895
(Earnings) Attributable to Valencia Non-controlling interest	(13,563		)	—				—			—				(13,563		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	—				—			—				(528		)
Net Earnings Attributable to PNMR	$	(45,215	)	$	(24,061	)		$	120,509		$	(9,429	)		$	41,804
Net Earnings Attributable to PNMR per Common Share:
Basic	$	(0.49	)												$	0.48
Diluted	$	(0.49	)												$	0.48
Number of Shares Used in Calculating Earnings per Share
Basic	91,557										(4,778		)	D	86,779
Diluted	91,557										(4,778		)	D
											263			L	87,042

PNM RESOURCES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS

(Unaudited)

(1) PNMR Basis of Presentation

Historical information for PNMR Resources, Inc. (“PNMR”) as of and for the nine months ended September 30, 2011 and for the year ended December 31, 2010 have been derived from PNMR's historical financial statements.

(2) Sale of FCP Enterprises, Inc. and Subsidiaries to Direct LP, Inc.

As previously reported, on September 23, 2011 PNMR entered into an agreement for the sale of FCP Enterprises, Inc. and Subsidiaries, which are indirect wholly-owned subsidiaries of PNMR and comprise the “First Choice” business segment of PNM to Direct LP, Inc. for $270.0 million, subject to adjustment to reflect the actual amounts of certain components of working capital at closing, pursuant to a Stock Purchase Agreement dated September 23, 2011. Closing occurred on November 1, 2011, with PNMR receiving $329.3 million, which includes an estimate of the components of working capital at closing. Such amount is subject to adjustment based on the actual amounts of the components of working capital at October 31, 2011.

PNMR expects to use the net proceeds from the sale of First Choice to repurchase, depending on market conditions, certain of PNMR's outstanding debt and equity and for other corporate purposes, including the repayment of short-term debt. The PNMR Board of Directors has approved the repurchase of up to $75 million of PNMR's long-term debt and equity repurchases of up to $230 million. As discussed in 4 D. below, on September 23, 2011, PNMR entered into an agreement to purchase all of its outstanding Convertible Preferred Stock, Series A. The affects of the purchase of preferred stock is reflected in the Unaudited Pro Forma Condensed Consolidated Financial Statements. The amount and timing of additional purchases will depend on a number of factors, including the price and availability of PNMR debt and shares, trading volume, and general market conditions.

On October 24, 2011, PNMR commenced a cash tender offer to purchase up to $50.0 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015. The price PNMR is offering to pay for the notes is their principal amount plus a premium of up to 17%, depending on when the notes are tendered, plus accrued and unpaid interest. The tender offer is scheduled to expire on November 21, 2011. Since the results of the tender offer are not known, the affects of it are not reflected in the Unaudited Pro Forma Condensed Consolidated Financial Statements. If successfully completed, the tender offer would result in a decrease in cash, a decrease in deferred charges for the removal of deferred debt acquisition costs, decreases in long-term debt and accrued interest payable, a decrease in deferred income taxes, and a decrease in retained earnings, as well as decreases in interest expense and related income tax impacts.

PNMR is also considering various alternatives related to the repurchase of currently outstanding shares of common stock. Because no agreements have been reached regarding any such repurchase, the affects of it are not reflected in the Unaudited Pro Forma Condensed Consolidated Financial Statements. If successfully completed, the common stock repurchase would result in decreases in cash and common stockholders' equity, as well as reducing the average number of common shares used to compute earnings per share.

PNMR has reflected the sale of First Choice in the pro forma condensed consolidated financial statements by (1) removing the historical First Choice amounts from the Condensed Consolidated Balance Sheet as of September 30, 2011 and the Condensed Consolidated Statement of Earnings for the nine months ended September 30, 2011 and the year ended December 31, 2010; (2) reflecting receipt of the proceeds from the sale of First Choice and the use of such proceeds to the extent known; (3) increased general and administrative expenses to reflect the pro forma elimination of billings to First Choice for services provided by PNMR to First Choice pursuant to a services agreement; and (4) adjusting for income tax effects of the previous items.

(3) Reduction in Ownership of Optim Energy

As previously reported, in January 2007, PNMR and ECJV Holdings, LLC (“ECJV”), a wholly owned subsidiary of Cascade Investment, L.L.C., created EnergyCo, LLC (“EnergyCo”), which name was later changed to Optim Energy, LLC (“Optim Energy”). PNMR and ECJV each had a 50% ownership interest in Optim Energy, a limited liability company. On September 23, 2011, PNMR and ECJV entered into an agreement that reduced PNMR's ownership in Optim Energy from 50% to 1%. PNMR performed an impairment analysis of its investment in Optim Energy at December 31, 2010, determined its investment was fully impaired, and reduced the carrying value of its investment to zero as of December 31, 2010. In accordance with generally accepted accounting principles, PNMR has not recorded losses (or income) associated with its investment in Optim Energy in 2011. PNMR

has reflected the reduction in ownership in the pro forma condensed consolidated financial statements by (1) removing PNMR's share of the losses of Optim Energy recorded under the equity method of accounting during the year ended December 31, 2010; (2) adjusting the impairment charge that was recorded during the year ended December 31, 2010 to reflect the impairment that would have been recorded if the reduction in ownership had occurred as of January 1, 2010; (3) increasing general and administrative expenses to reflect the pro forma elimination of billings to Optim Energy for services provided by PNMR to Optim Energy pursuant to a services agreement; and (4) adjusting for income tax effects of the previous items. Due to PNMR fully impairing its investment in Optim Energy as of December 31, 2010, the reduction in ownership had no impact on PNMR's Condensed Consolidated Balance Sheet as of September 30, 2011 or the Condensed Consolidated Statement of Earnings for the nine months ended September 30, 2011.

(4) Pro Forma Adjustments

Following are brief descriptions of the pro forma adjustments to the Condensed Consolidated Financial Statements to reflect the sale of First Choice and to reflect the reduction in PNMR's ownership in Optim Energy. The Pro Forma Condensed Consolidated Balance Sheet reflects the transactions as if they had occurred at September 30, 2011; and the Pro Forma Condensed Consolidated Statements of Earnings reflects the transactions as if they had occurred immediately prior to January 1, 2010.

A. Removes First Choice balances from the PNMR historical balances as of and for the nine months ended September 30, 2011 and for the year ended December 31, 2010.

B. Reflects the proceeds from the sale of First Choice as if closing had occurred as of September 30, 2011, based on the sales price of $270.0 million and the September 30, 2011 amounts of the components of working capital included in the pricing methodology.

C. Reflects the gain on the sale of First Choice, including estimated transaction costs, and related income tax impacts.

D. On September 23, 2011, PNMR entered into an agreement to purchase all of its outstanding Convertible Preferred Stock, Series A, which was reflected as a current liability of $73.5 million at September 30, 2011. Such liability was paid on October 5, 2011, through a borrowing under PNMR's revolving credit facility. The borrowing was repaid on November 1, 2011 with a portion of the proceeds from the sale of First Choice. The purchase of the preferred stock is reflected as reductions of cash and the liability for the purchase of preferred stock. The purchase of the preferred stock also resulted in a reduction in the number of shares used to calculate earnings per share of 4,637,985 shares for the nine months ended September 30, 2011 and of 4,778,000 shares for the year ended December 31, 2010.

E. On October 6, 2011, PNM completed the offering of $160.0 million of its senior unsecured notes. The notes were sold at 99.857% of face value and bear interest at an effective rate of 5.369%. This transaction is reflected as an increase in cash, an increase in deferred charges for the expenses of the offering, and an increase in long-term debt, as well as increases in interest expense and related income tax impacts.

F. With the proceeds received from the sale of First Choice, PNMR paid all outstanding borrowings under its revolving credit facility. PNMR also loaned Public Service Company of New Mexico (“PNM”), a wholly owned subsidiary of PNMR, $63.8 million that PNM used, together with other available cash, to pay all outstanding borrowings under its revolving credit facility. These transactions, including the cash proceeds from the note offering described in E above, are reflected as reductions of $289.0 million in cash and short-term debt at September 30, 2011, as well as reductions in interest expense and related income tax impacts.

G. Reflects the removal of PNMR's share of losses of Optim Energy recorded under the equity method of accounting for the year ended December 31, 2010. PNMR recorded no losses related to Optim Energy in the nine months ended September 30, 2011 since PNMR fully impaired its investment in Optim Energy at December 31, 2010.

H. Reflects adjusting the impairment loss related to PNMR's investment in Optim Energy recognized in the year ended December 31, 2010. If the reduction in PNMR's ownership of Optim Energy had occurred as of January 1, 2010, PNMR's carrying value of Optim Energy would have been $3.9 million. Accordingly, the amount of the impairment reflected in the year ended December 31, 2010 would have been the adjusted carrying value of $3.9 million.

I. Reflects the income tax impact of the removal of the equity losses of Optim Energy and the adjustment of the impairment loss related to PNMR's investment in Optim Energy for the year-ended December 31, 2010.

J. Reflects additional general and administrative expenses due to the elimination of billings to Optim Energy for services

provided by PNMR to Optim Energy pursuant to a services agreement and related income tax impacts.

K. Reflects additional general and administrative expenses due to the elimination of billings to First Choice for services provided by PNMR to First Choice pursuant to a services agreement and related income tax impacts.

L. Reflects the number of dilutive common stock equivalents for the year ended December 31, 2010 attributable to stock option and restricted stock awards. These equivalents were not included in the historical number since they were anti-dilutive due to the historical loss for the year.

M. Reflects the reversal of the elimination, made in the historical Consolidated Statements of Earnings of PNMR, of intercompany revenue received by Texas-New Mexico Power Company, a wholly owned subsidiary of PNMR, from First Choice.

XML

Capitalization, Short-term Debt (Details) (USD $)					0 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Oct. 31, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Nov. 01, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member] Issuance of Debt [Member]	Oct. 31, 2011 Texas-New Mexico Power Company [Member] Affiliated Entity [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Affiliated Entity [Member]	Oct. 31, 2011 PNM Resources [Member] Revolving credit facility [Member] Refinancing of Debt [Member]	Oct. 31, 2011 Public Service Company of New Mexico [Member] Revolving credit facility [Member] Refinancing of Debt [Member]	Oct. 30, 2011 PNM Resources [Member] Revolving credit facility [Member]	Sep. 30, 2011 PNM Resources [Member] Revolving credit facility [Member]	Dec. 31, 2010 PNM Resources [Member] Revolving credit facility [Member]	Sep. 30, 2011 PNM Resources [Member] Local lines of credit [Member]	Dec. 31, 2010 PNM Resources [Member] Local lines of credit [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member]	Oct. 30, 2011 Public Service Company of New Mexico [Member] Revolving credit facility [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Revolving credit facility [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Revolving credit facility [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member]	Dec. 31, 2010 Texas-New Mexico Power Company [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Revolving credit facility [Member]	Dec. 31, 2010 Texas-New Mexico Power Company [Member] Revolving credit facility [Member]	Sep. 30, 2011 Line of Credit [Member]	Dec. 31, 2010 Line of Credit [Member]
Short-term Debt [Line Items]
Proceeds from Related Party Debt					$ 63,800,000
Short-term debt – affiliate			63,800,000	0		5,400,000	0													0	1,200,000
Line of Credit Facility, Maximum Borrowing Capacity								300,000,000	400,000,000	517,000,000			5,000,000				368,000,000					75,000,000
Short-term debt	$ 289,000,000	$ 222,000,000									$ 32,000,000	$ 32,000,000	$ 0	$ 0	$ 257,000,000	$ 190,000,000		$ 257,000,000	$ 190,000,000			$ 0	$ 0	$ 289,000,000	$ 222,000,000

XML

Condensed Consolidated Balance Sheets (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents	$ 25,760
Cash and cash equivalents	22,298	15,404
Accounts receivable, net of allowance for uncollectible accounts of $1,645 and $11,178 for PNMR and $1,645 and $1,483 for PNM	107,637	97,245
Unbilled revenues	47,793	71,453
Other receivables	46,955	60,562
Materials, supplies, and fuel stock	53,092	52,479
Regulatory assets	28,693	36,292
Commodity derivative instruments	3,716	15,999
Income taxes receivable	99,506	97,450
Current portion of accumulated deferred income taxes	886	886
Current assets of business unit held for sale	166,119	0
Other current assets	49,043	96,110
Total current assets	625,738	543,880
Other Property and Investments:
Investment in PVNGS lessor notes	79,390	103,871
Investments held by NDT	157,001	156,922
Other investments	14,639	18,791
Non-utility property, net of accumulated depreciation of $125 and $2,307 for PNMR	5,139	7,333
Total other property and investments	256,169	286,917
Utility Plant:
Plant in service and plant held for future use	4,998,685	4,860,614
Less accumulated depreciation and amortization	1,686,971	1,626,693
Net plant in service and plant held for future use	3,311,714	3,233,921
Construction work in progress	159,918	137,622
Nuclear fuel, net of accumulated amortization of $36,722 and $26,247 for PNMR and PNM	78,218	72,901
Net utility plant	3,549,850	3,444,444
Deferred Charges and Other Assets:
Regulatory assets	475,937	502,467
Goodwill	278,297	321,310
Goodwill	321,310
Other intangible assets, net of accumulated amortization of none and $5,414 for PNMR	0	26,425
Commodity derivative instruments	247	5,264
Non-current assets of business unit held for sale	101,059	0
Other deferred charges	85,343	94,376
Total deferred charges and other assets	940,883	949,842
Assets	5,372,640	5,225,083
Current Liabilities:
Short-term debt	289,000	222,000
Current installments of long-term debt	2,252	2,252
Accounts payable	71,949	95,969
Accrued interest and taxes	82,636	47,783
Regulatory liabilities	429	724
Commodity derivative instruments	1,746	31,407
Dividends declared	10,966	11,565
Repurchase of Series A Preferred Stock	73,475	0
Current liabilities of business unit held for sale	103,915	0
Other current liabilities	76,281	108,424
Total current liabilities	712,649	520,124
Long-term Debt	1,564,077	1,563,595
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	582,485	540,106
Accumulated deferred investment tax credits	16,350	18,089
Regulatory liabilities	363,087	342,465
Asset retirement obligations	77,290	76,637
Accrued pension liability and postretirement benefit cost	227,401	270,172
Commodity derivative instruments	1,913	12,831
Non-current liabilities of business unit held for sale	17,596	0
Other deferred credits	123,054	147,616
Total deferred credits and other liabilities	1,409,176	1,407,916
Total liabilities	3,685,902	3,491,635
Commitments and Contingencies (See Note 9)
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:
Company Convertible Preferred Stock, Series A without mandatory redemption requirements	0	100,000
Common stock outstanding	1,318,539	1,290,465
Accumulated other comprehensive income (loss), net of income taxes	(72,913)	(68,666)
Retained earnings	345,614	314,943
Total PNMR common stockholders' equity	1,591,240	1,536,742
Non-controlling interest in Valencia	83,969	85,177
Total equity	1,675,209	1,721,919
Total liabilities and stockholders' equity	5,372,640	5,225,083
Public Service Company of New Mexico [Member]
Current Assets:
Cash and cash equivalents	5,034	10,336
Accounts receivable, net of allowance for uncollectible accounts of $1,645 and $11,178 for PNMR and $1,645 and $1,483 for PNM	80,154	58,785
Unbilled revenues	41,417	39,053
Other receivables	45,724	56,951
Affiliate receivables	8,893	8,605
Materials, supplies, and fuel stock	50,429	49,454
Regulatory assets	27,630	35,835
Commodity derivative instruments	3,716	1,443
Income taxes receivable	82,662	76,941
Other current assets	41,653	46,635
Total current assets	387,312	384,038
Other Property and Investments:
Investment in PVNGS lessor notes	79,390	103,871
Investments held by NDT	157,001	156,922
Other investments	4,193	5,068
Non-utility property, net of accumulated depreciation of $125 and $2,307 for PNMR	976	976
Total other property and investments	241,560	266,837
Utility Plant:
Plant in service and plant held for future use	3,930,362	3,818,722
Less accumulated depreciation and amortization	1,294,723	1,259,957
Net plant in service and plant held for future use	2,635,639	2,558,765
Construction work in progress	124,607	115,628
Nuclear fuel, net of accumulated amortization of $36,722 and $26,247 for PNMR and PNM	78,218	72,901
Net utility plant	2,838,464	2,747,294
Deferred Charges and Other Assets:
Regulatory assets	341,089	357,944
Goodwill	51,632	51,632
Commodity derivative instruments	247	0
Other deferred charges	76,164	67,828
Total deferred charges and other assets	469,132	477,404
Assets	3,936,468	3,875,573
Current Liabilities:
Short-term debt	257,000	190,000
Accounts payable	48,077	51,931
Affiliate payables	17,788	8,528
Accrued interest and taxes	49,680	25,773
Regulatory liabilities	429	724
Commodity derivative instruments	1,746	3,110
Dividends declared	132	39,254
Current portion of accumulated deferred income taxes	9,783	9,783
Other current liabilities	53,943	65,858
Total current liabilities	438,578	394,961
Long-term Debt	1,055,760	1,055,748
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	463,918	446,657
Accumulated deferred investment tax credits	16,350	18,089
Regulatory liabilities	320,518	299,763
Asset retirement obligations	76,499	75,888
Accrued pension liability and postretirement benefit cost	213,607	253,948
Commodity derivative instruments	1,913	2,009
Other deferred credits	103,396	108,455
Total deferred credits and other liabilities	1,196,201	1,204,809
Total liabilities	2,690,539	2,655,518
Commitments and Contingencies (See Note 9)
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements	11,529	11,529
Equity:
Common stock outstanding	1,018,776	1,018,776
Accumulated other comprehensive income (loss), net of income taxes	(71,966)	(66,786)
Retained earnings	203,621	171,359
Total PNMR common stockholders' equity	1,150,431	1,123,349
Non-controlling interest in Valencia	83,969	85,177
Total equity	1,234,400	1,208,526
Total liabilities and stockholders' equity	3,936,468	3,875,573
Texas-New Mexico Power Company [Member]
Current Assets:
Cash and cash equivalents	9,000	1
Accounts receivable, net of allowance for uncollectible accounts of $1,645 and $11,178 for PNMR and $1,645 and $1,483 for PNM	20,851	12,742
Unbilled revenues	6,376	5,734
Other receivables	696	1,677
Affiliate receivables	5,962	3,956
Materials, supplies, and fuel stock	2,663	2,787
Regulatory assets	1,063	457
Current portion of accumulated deferred income taxes	1,876	1,876
Other current assets	896	618
Total current assets	49,383	29,848
Other Property and Investments:
Other investments	267	282
Non-utility property, net of accumulated depreciation of $125 and $2,307 for PNMR	2,240	2,244
Total other property and investments	2,507	2,526
Utility Plant:
Plant in service and plant held for future use	910,202	885,325
Less accumulated depreciation and amortization	318,863	302,333
Net plant in service and plant held for future use	591,339	582,992
Construction work in progress	30,062	12,375
Net utility plant	621,401	595,367
Deferred Charges and Other Assets:
Regulatory assets	134,848	144,522
Goodwill	226,665	226,665
Other deferred charges	6,809	12,029
Total deferred charges and other assets	368,322	383,216
Assets	1,041,613	1,010,957
Current Liabilities:
Short-term debt – affiliate	0	1,200
Accounts payable	11,831	5,537
Affiliate payables	2,506	1,015
Accrued interest and taxes	27,463	23,185
Other current liabilities	3,133	3,292
Total current liabilities	44,933	34,229
Long-term Debt	310,807	310,337
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	152,608	142,121
Regulatory liabilities	42,569	42,702
Asset retirement obligations	684	648
Accrued pension liability and postretirement benefit cost	13,794	16,224
Other deferred credits	11,961	11,413
Total deferred credits and other liabilities	221,616	213,108
Total liabilities	577,356	557,674
Commitments and Contingencies (See Note 9)
Equity:
Paid-in-capital	423,042	430,108
Common stock outstanding	64	64
Accumulated other comprehensive income (loss), net of income taxes	(579)	(1,485)
Retained earnings	41,730	24,596
Total PNMR common stockholders' equity	464,257	453,283
Total liabilities and stockholders' equity	$ 1,041,613	$ 1,010,957

XML

Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data	Sep. 30, 2011	Dec. 31, 2010
Allowance for uncollectible accounts	$ 1,645	$ 11,178
Accumulated depreciation, non-utility property	125	2,307
Accumulated depreciation, nuclear fuel	36,722	26,247
Accumulated depreciation, other intangible assets	0	5,414
Cumulative preferred stock of subsidiary, stated value	$ 100.00	$ 100.00
Cumulative preferred stock of subsidiary, shares authorized	115,293	115,293
Cumulative preferred stock of subsidiary, shares authorized	10,000,000	10,000,000
Cumulative preferred stock of subsidiary, shares issued	115,293	115,293
Convertible preferred stock, stated value	$ 0.00	$ 0.00
Convertible preferred stock, shares authorized	10,000,000	10,000,000
Convertible preferred stock, shares issued	0	477,800
Convertible preferred stock, shares outstanding	0	477,800
Common stock, par value	$ 0.00	$ 0.00
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	86,673,174	86,673,174
Common stock, shares outstanding	86,673,174	86,673,174
Public Service Company of New Mexico [Member]
Allowance for uncollectible accounts	1,645	1,483
Accumulated depreciation, nuclear fuel	$ 36,722	$ 26,247
Cumulative preferred stock of subsidiary, stated value	$ 100	$ 100
Cumulative preferred stock of subsidiary, shares authorized	10,000,000	10,000,000
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
Cumulative preferred stock of subsidiary, shares issued	115,293	115,293
Cumulative preferred stock of subsidiary, shares outstanding	115,293	115,293
Texas-New Mexico Power Company [Member]
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
Common stock, par value	$ 10	$ 10

XML

Pension and Other Postretirement Benefit Plans (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
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	8,202,000	8,518,000	24,606,000	25,555,000
Long-term return on plan assets	(9,269,000)	(9,339,000)	(27,807,000)	(28,016,000)
Amortization of net loss	2,302,000	1,613,000	6,906,000	4,838,000
Amortization of prior service cost	79,000	79,000	237,000	238,000
Net periodic benefit cost	1,314,000	871,000	3,942,000	2,615,000
Defined Benefit Plan, Contributions by Employer	20,500,000	6,500,000	34,000,000	13,100,000
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	7,500,000		7,500,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	163,900,000		163,900,000
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	65,000	105,000	195,000	314,000
Interest cost	1,345,000	1,913,000	4,035,000	5,738,000
Long-term return on plan assets	(1,347,000)	(1,393,000)	(4,041,000)	(4,179,000)
Amortization of net loss	801,000	1,372,000	2,403,000	4,116,000
Amortization of prior service cost	(662,000)	(1,036,000)	(1,986,000)	(3,107,000)
Net periodic benefit cost	202,000	961,000	606,000	2,882,000
Defined Benefit Plan, Contributions by Employer	700,000	400,000	1,900,000	1,600,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	2,600,000		2,600,000
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	233,000	263,000	699,000	790,000
Long-term return on plan assets	0	0	0	0
Amortization of net loss	23,000	18,000	69,000	53,000
Amortization of prior service cost	0	0	0	0
Net periodic benefit cost	256,000	281,000	768,000	843,000
Defined Benefit Plan, Contributions by Employer	400,000	400,000	1,200,000	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] | Maximum [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Contributions by Employer	100,000	100,000	100,000	100,000
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	951,000	1,032,000	2,853,000	3,095,000
Long-term return on plan assets	(1,368,000)	(1,449,000)	(4,104,000)	(4,346,000)
Amortization of net loss	86,000	0	258,000	0
Amortization of prior service cost	0	0	0	0
Net periodic benefit cost	(331,000)	(417,000)	(993,000)	(1,251,000)
Defined Benefit Plan, Contributions by Employer	800,000	200,000	1,000,000	200,000
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	200,000		200,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	6,000,000		6,000,000
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	77,000	72,000	231,000	217,000
Interest cost	163,000	178,000	489,000	533,000
Long-term return on plan assets	(133,000)	(129,000)	(399,000)	(386,000)
Amortization of net loss	(48,000)	(49,000)	(144,000)	(147,000)
Amortization of prior service cost	15,000	15,000	45,000	45,000
Net periodic benefit cost	74,000	87,000	222,000	262,000
Defined Benefit Plan, Contributions by Employer	0	0	400,000	600,000
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	12,000	13,000	36,000	39,000
Long-term return on plan assets	0	0	0	0
Amortization of net loss	0	(1,000)	0	(3,000)
Amortization of prior service cost	0	0	0	0
Net periodic benefit cost	12,000	12,000	36,000	36,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	$ 100,000		$ 100,000

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Goodwill and Other Intangible Assets

9 Months Ended

Sep. 30, 2011

Goodwill and Other Intangible Assets [Abstract]

Goodwill and Intangible Assets Disclosure [Text Block]

Goodwill and Other Intangible Assets

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. Additionally, the trade name “First Choice” and the First Choice customer list were acquired in the TNP acquisition. The trade name was considered to have an indefinite useful life; therefore, no amortization was recorded. The useful life of the customer list was estimated to be approximately eight years.

The Company evaluates its goodwill and non-amortizing intangible assets for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill or intangible assets may be impaired. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit. A discounted cash flow methodology is primarily used to estimate the fair value of each 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 for each reporting unit.

For non-amortizing intangibles other than goodwill, the Company compares the fair value of the intangible asset to its recorded value. For goodwill, the first step of the impairment test requires that the Company compare the fair value of each reporting unit with its carrying value, including goodwill. If as a result of this analysis, the Company concludes there is an indication of impairment in a reporting unit having goodwill, the Company 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 Company 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.

The annual evaluations performed as of April 1, 2011 and 2010 did not indicate impairments of the goodwill or other intangible assets of any of the Company’s reporting units. Since the annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill, other intangible assets, and impairments is contained in Note 25 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

XML

Document and Entity Information Document	9 Months Ended
	Sep. 30, 2011	Nov. 01, 2011
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, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		86,673,174
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

Stock-Based Compensation (Details) (USD $)	9 Months Ended
	Sep. 30, 2011 years		Sep. 30, 2010
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options, Outstanding at beginning of period, Shares	3,948,262
Options, Outstanding at beginning of period, Weighted-Average Exercise Price	$ 18.33
Options, Granted, Shares	0
Options, Granted, Weighted-Average Exercise Price	$ 0.00
Options, Exercised, Shares	(254,394)
Options, Exercised, Weighted-Average Exercise Price	$ 10.99
Options, Forfeited, Shares	(10,333)
Options, Forfeited, Weighted-Average Exercise Price	$ 11.26
Options, Expired, Shares	(102,338)
Options, Expired, Weighted-Average Exercise Price	$ 24.96
Options, Outstanding at end of period, Shares	3,581,197
Options, Outstanding at end of period, Weighted-Average Exercise Price	$ 18.68
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options, Outstanding at end of period, Aggregate Intrinsic Value	$ 8,950,188	[1]
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years)	5.12
Options, Exercisable at end of period, Shares	3,045,556
Options, Exercisable at end of period, Weighted-Average Exercise Price	$ 21.97
Options, Exercisable at end of period, Aggregate Intrinsic Value	6,011,541
Options, Exercisable at end of period, Weighted-Average Remaining Contract Life (years)	4.60
Options, Outstanding at end of period, No intrinsic value	1,923,608
Weighted-average grant date fair value options granted (dollars per share)	$ 0.00		$ 3.05
Total fair value of options that vested	1,189,000		1,027,000
Total intrinsic value of options exercised	1,077,000		474,000
Executive [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options / Restricted Stock available for future grant	560,461
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested Restricted Stock, Granted, Shares	88,913
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options / Restricted Stock available for future grant	4,820,656	[2]
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested Restricted Stock, Nonvested at beginning of period, Shares	237,021
Nonvested Restricted Stock, Nonvested at beginning of period, Weighted-Average Grant-Date Fair Value	$ 9.24
Nonvested Restricted Stock, Granted, Shares	308,985
Nonvested Restricted Stock, Granted, Weighted-Average Grant-Date Fair Value	$ 13.10		$ 9.37
Nonvested Restricted Stock, Vested, Shares	(113,576)
Nonvested Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value	$ 9.54
Nonvested Restricted Stock, Forfeited, Shares	(1,000)
Nonvested Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value	$ 13.67
Nonvested Restricted Stock, Nonvested at end of period, Shares	431,430
Nonvested Restricted Stock, Nonvested at end of period, Weighted-Average Grant-Date Fair Value	$ 11.92
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	$ 1,084,000		$ 1,365,000
Share Based Compensation Arrangement by Share Based Payment Award Fair Value Assumptions Expected Quarterly Dividend Rate	$ 0.125		$ 0.125
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.20%		1.36%

[1] At September 30, 2011, the exercise price of 1,923,608 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

[2] Includes shares available for grants of restricted stock.

XML

Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2011

Variable Interest Entities [Abstract]

Noncontrolling Interest Summarized Financial Information [Table Text Block]

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
				(In thousands)
Operating revenues	$	5,505		$	5,275		$	15,024		$	14,502
Operating expenses	(1,394		)	(1,366		)	(4,260		)	(4,197		)
Earnings attributable to non-controlling interest	$	4,111		$	3,909		$	10,764		$	10,305

Financial Position

	September 30,		December 31,
	2011		2010
	(In thousands)
Current assets	$	3,588	$	2,372
Net property, plant and equipment	81,493		83,617
Total assets	85,081		85,989
Current liabilities	1,112		812
Owners’ equity – non-controlling interest	$	83,969	$	85,177

XML

Earnings Per Share (Details) (USD $) In Thousands, except Share data	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Schedule of Earnings Per Share Basic and Diluted [Line Items]
Net Earnings Attributable to PNMR	$ 43,662		$ 48,552		$ 64,366		$ 62,981
Average Number of Common Shares:
Outstanding during period	86,673,000		86,673,000		86,673,000		86,673,000
Equivalents from convertible preferred stock	4,363,000		4,778,000		4,638,000		4,778,000
Vested awards of restricted stock	164,000		111,000		154,000		105,000
Average Shares - Basic	91,200,000		91,562,000		91,465,000		91,556,000
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	542,000	[1]	219,000	[1]	516,000	[1]	258,000	[1]
Average Shares - Diluted	91,742,000		91,781,000		91,981,000		91,814,000
Net Earnings Per Share of Common Stock
Basic (dollars per share)	$ 0.48		$ 0.53		$ 0.70		$ 0.69
Diluted (dollars per share)	$ 0.48		$ 0.53		$ 0.70		$ 0.69
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price					1,923,608

[1] Excludes the effect of out-of-the-money options for 1,923,608 shares of common stock at September 30, 2011.

XML

Fair Value of Derivative and Other Financial Instruments

9 Months Ended

Sep. 30, 2011

Fair Value of Derivative and Other Financial Instruments [Abstract]

Derivatives and Fair Value [Text Block]

Fair Value of Derivative and Other Financial Instruments

Energy Related Derivative Contracts

Overview

The Company is exposed to certain risks relating to its ongoing business operations. 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 or fuel used to generate electricity, or to manage anticipated generation capacity in excess of forecasted demand from existing customers. Substantially all of the Company’s energy related derivative contracts manage commodity risk and the Company does not currently engage in speculative trading.

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. The Company 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. The Company monitors the market risk of its commodity contracts using VaR and GEaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.

PNM is required to meet the demand and energy needs of its retail and firm requirements customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm requirements 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. 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.

First Choice was responsible for energy supply related to the sale of electricity to retail customers in Texas. TECA contains no provisions for the specific recovery of fuel and purchased power costs. The rates charged to First Choice customers were negotiated with each customer. First Choice purchased wholesale power in the competitive ERCOT wholesale market and sold power to retail customers in the competitive ERCOT retail market. Many of these retail customers bought power from First Choice for a contracted period of time at a fixed price so First Choice was exposed to price risk if the wholesale power price changed during the time of the contract. First Choice’s strategy was to minimize its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins. However, if actual fixed price retail loads varied significantly from forecasts (for example, due to extreme weather, other significant load changes or contract breaches), First Choice had a residual exposure to wholesale power price risk for the mismatch between the forecast and actual load.

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 settle.

For derivative transactions meeting the definition of a cash flow hedge, the Company documents the relationships between the hedging instruments and the items being hedged. This documentation includes the strategy that supports executing the specific transaction and the methods utilized to assess the effectiveness of the hedges. Changes in the fair value of contracts qualifying for cash flow hedge accounting are included in AOCI to the extent effective. Ineffectiveness gains and losses were immaterial for all periods presented. Gains or losses related to cash flow hedge instruments, including those de-designated, are reclassified from AOCI when the hedged transaction settles and impacts earnings. Based on market prices at September 30, 2011, after-tax losses of $0.1 million for PNMR and zero for PNM would be reclassified from AOCI into earnings during the next twelve months. However, the actual amount reclassified into earnings may vary due to changes in the timing or nature of the underlying transactions. As of September 30, 2011 and December 31, 2010, the Company is 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 either economic hedges or trading transactions. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. Trading transactions included speculative transactions, which the Company ceased in 2008, and transactions that lock in margin with no forward market risk and are not economic hedges. Changes in the fair value of these transactions are reflected on a net basis in operating revenues.

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 own 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.

The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements. At September 30, 2011 and December 31, 2010, amounts recognized for the legal right to reclaim cash collateral were $0.3 million and $3.4 million for PNMR and zero and $3.0 million for PNM. In addition, at September 30, 2011 and December 31, 2010, amounts posted as cash collateral under margin arrangements were $28.9 million and $32.0 million for PNMR and $0.1 million and $2.1 million for PNM. Cash collateral amounts are included in other current assets on the Condensed Consolidated Balance Sheets. PNMR and PNM had no obligations to return cash collateral at September 30, 2011 and December 31, 2010.

Commodity Derivatives

Commodity derivative instruments are summarized as follows:

	PNMR						PNM
	Economic Hedges						Economic Hedges
	September 30, 2011			December 31, 2010			September 30, 2011			December 31, 2010
	(In thousands)
Current assets	$	32,168		$	15,999		$	3,716		$	1,443
Deferred charges	9,064			5,264			247			—
	41,232			21,263			3,963			1,443
Current liabilities	(41,018		)	(31,407		)	(1,746		)	(3,110		)
Long-term liabilities	(16,373		)	(12,831		)	(1,913		)	(2,009		)
	(57,391		)	(44,238		)	(3,659		)	(5,119		)
Net	$	(16,159	)	$	(22,975	)	$	304		$	(3,676	)

The Company had no trading or designated cash flow hedge transactions at September 30, 2011 and December 31, 2010. On April 20, 2010, PNM received NMPRC approval of a hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.8 million of current assets, less than $0.1 million of deferred charges, $0.4 million in current liabilities, and less than $0.1 million of long-term liabilities at September 30, 2011, and $0.6 million of current assets at December 31, 2010 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.

The following table presents the effect of commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.

	Economic Hedges						Trading Transactions					Qualified Cash Flow Hedges
	September 30,						September 30,					September 30,
	2011			2010			2011		2010			2011			2010
Three Months Ended	(In thousands)
PNMR
Electric operating revenues	$	2,915		$	(2,131	)	$	—	$	30		$	—		$	9,006
Cost of energy	(2,873		)	(20,222		)	—		—			66			(684		)
Total gain (loss)	$	42		$	(22,353	)	$	—	$	30		$	66		$	8,322
Recognized in OCI												$	(66	)	$	(6,531	)
PNM
Electric operating revenues	$	2,915		$	(2,131	)	$	—	$	—		$	—		$	9,006
Cost of energy	(562		)	(1,781		)	—		—			—			(35		)
Total gain (loss)	$	2,353		$	(3,912	)	$	—	$	—		$	—		$	8,971
Recognized in OCI												$	—		$	(7,181	)
Nine Months Ended
PNMR
Electric operating revenues	$	4,250		$	(4,138	)	$	—	$	(3	)	$	—		$	22,294
Cost of energy	(2,788		)	(49,451		)	—		—			(183		)	(1,930		)
Total gain (loss)	$	1,462		$	(53,589	)	$	—	$	(3	)	$	(183	)	$	20,364
Recognized in OCI												$	183		$	(11,349	)
PNM
Electric operating revenues	$	4,250		$	(4,138	)	$	—	$	—		$	—		$	22,294
Cost of energy	(404		)	(5,443		)	—		—			—			(21		)
Total gain (loss)	$	3,846		$	(9,581	)	$	—	$	—		$	—		$	22,273
Recognized in OCI												$	—		$	(13,259	)

Commodity contract volume positions are presented in Decatherms 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
	Decatherms	MWh
September 30, 2011
PNMR	27,187,500	3,597,170
PNM	1,425,000	(961,192	)
December 31, 2010
PNMR	22,767,500	1,693,431
PNM	1,882,500	(990,120	)

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 such counterparty 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, 2011
PNMR	$	12,787	$	—	$	4,026
PNM	$	3,486	$	—	$	3,064
December 31, 2010
PNMR	$	8,113	$	—	$	2,642
PNM	$	291	$	—	$	119

Sale of Power from PVNGS Unit 3

In April 2008, PNM entered into three separate contracts for the sale of capacity and energy related to its entire ownership interest in PVNGS Unit 3, which is 135 MW.  Under two of the contracts, PNM sold 90 MW of firm capacity and energy.  Under the third contract, PNM sold 45 MW of unit contingent capacity and energy. The term of the contracts was May 1, 2008 through December 31, 2010.  Under the two firm contracts, the two buyers made prepayments of $40.6 million and $30.0 million.  These amounts were recorded as deferred revenue and were amortized over the life of the contracts. The prepayments received under the firm contracts, as well as required subsequent monthly payments on them, are shown as a financing activity in the Condensed Consolidated Statements of Cash Flows as required by GAAP. The firm contracts were accounted for as cash flow hedges and changes in fair value were included in AOCI. The contingent contract was accounted for as a normal sale. Beginning January 1, 2011, PNM is selling its 135 MW interest in PVNGS Unit 3 daily at market prices. PNM has established fixed rates for the majority of these sales through the end of 2011 through financial hedging arrangements that are accounted for as economic hedges.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS. The NDT holds equity and fixed income securities. PNMR and PNM do not have any unrealized losses on available-for-sale securities. The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table.

	September 30, 2011				December 31, 2010
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Equity securities:
Domestic value	$	1,137	$	22,051	$	5,108	$	25,491
Domestic growth	12,356		47,358		17,239		48,237
Multinational	243		12,509		2,730		10,670
Fixed income securities:
Municipals	2,486		39,316		837		37,595
U.S. Government	1,305		22,779		348		21,541
Corporate and other	728		9,292		573		8,402
Cash and equivalents	—		3,696		—		4,986
	$	18,255	$	157,001	$	26,835	$	156,922

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,
	2011			2010			2011			2010
				(In thousands)
Proceeds from sales	$	26,312		$	20,813		$	121,202		$	57,098
Gross realized gains	$	2,800		$	1,568		$	16,290		$	4,999
Gross realized (losses)	$	(1,847	)	$	(1,227	)	$	(4,129	)	$	(3,099	)

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, including the EIP lessor note.

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

At September 30, 2011, 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	$	683	$	—	$	—
After 1 year through 5 years	20,259		123,206		112,083
After 5 years through 10 years	10,740		3,370		—
Over 10 years	39,705		—		—
	$	71,387	$	126,576	$	112,083

The carrying amount and fair value of held-to-maturity debt securities and other non-derivative financial instruments (including current maturities) are:

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
PNMR
Long-term debt	$	1,566,329	$	1,751,691	$	1,565,847	$	1,659,674
Investment in PVNGS lessor notes	$	107,435	$	108,345	$	136,145	$	141,663
Other investments	$	14,639	$	21,070	$	18,791	$	21,675
PNM
Long-term debt	$	1,055,760	$	1,107,490	$	1,055,748	$	1,056,864
Investment in PVNGS lessor notes	$	107,435	$	108,345	$	136,145	$	141,663
Other investments	$	4,193	$	4,522	$	5,068	$	5,563
TNMP
Long-term debt	$	310,807	$	423,253	$	310,337	$	385,220
Other investments	$	267	$	267	$	282	$	282

The fair value of long-term debt shown above was primarily determined using quoted market values, as were certain items included in other investments. To the extent market values were not available, fair value was determined by discounting the cash flows for the instrument using quoted interest rates for comparable instruments.

Other 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 has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models.

For NDT 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. Fair values of Level 3 commodity derivatives are determined in a manner similar to those in Level 2, but are at a lower level in the hierarchy due to low transaction volume or market illiquidity that significantly limits the availability of observable market data.

Derivatives and Investments

The fair values of derivatives and investments that are recorded at fair value on the Condensed Consolidated Balance Sheets are as follows:

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
September 30, 2011				(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	3,696		$	3,696		$	—		$	—
Equity securities:
Domestic value	22,051			22,051			—			—
Domestic growth	47,358			47,358			—			—
Multinational	12,509			12,509			—			—
Fixed income securities:
U.S. government	22,779			18,149			4,630			—
Municipals	39,316			—			39,316			—
Corporate and other	9,292			—			9,292			—
Total NDT investments	$	157,001		$	103,763		$	53,238		$	—
PNMR
Commodity derivative assets	$	41,232		$	19,589		$	18,982		$	1,302
Commodity derivative liabilities	(57,391		)	(41,574		)	(14,094		)	(364		)
Net	$	(16,159	)	$	(21,985	)	$	4,888		$	938
PNM
Commodity derivative assets	$	3,963		$	—		$	3,963		$	—
Commodity derivative liabilities	(3,659		)	—			(3,659		)	—
Net	$	304		$	—		$	304		$	—

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
December 31, 2010	(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	4,986		$	4,986		$	—		$	—
Equity securities:
Domestic value	25,491			25,491			—			—
Domestic growth	48,237			48,237			—			—
Multinational	10,670			10,670			—			—
Fixed income securities:
U.S. government	21,541			16,613			4,928			—
Municipals	37,595			—			37,595			—
Corporate and other	8,402			—			8,402			—
Total NDT investments	$	156,922		$	105,997		$	50,925		$	—
PNMR
Commodity derivative assets	$	21,263		$	8,646		$	12,308		$	272
Commodity derivative liabilities	(44,238		)	(26,378		)	(16,729		)	(1,094		)
Net	$	(22,975	)	$	(17,732	)	$	(4,421	)	$	(822	)
PNM
Commodity derivative assets	$	1,443		$	—		$	1,443		$	—
Commodity derivative liabilities	(5,119		)	—			(5,119		)	—
Net	$	(3,676	)	$	—		$	(3,676	)	$	—

(1) The Level 1, 2 and 3 columns in the above table are presented based on the nature of each instrument. The total column is presented based on the balance sheet classification of the instruments and reflect unit of account reclassifications between commodity derivative assets and commodity derivative liabilities of $1.4 million for PNMR and zero for PNM at September 30, 2011 and less than $0.1 million for PNMR and zero for PNM at December 31, 2010. There were no transfers between levels for the three months and nine months ended September 30, 2011 and 2010.

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

	PNMR						PNM
	September 30,						September 30,
	2011			2010			2011		2010
Three Months Ended	(In thousands)
Balance at beginning of period	$	4,392		$	(278	)	$	—	$	—
Total gains (losses) included in earnings	(5,025		)	(945		)	—		—
Purchases	429			34			—		—
Settlements	1,142			(83		)	—		—
Balance at end of period	$	938		$	(1,272	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	589		$	(994	)	$	—	$	—
Nine Months Ended
Balance at beginning of period	$	(822	)	$	248		$	—	$	(17	)
Total gains (losses) included in earnings	201			(1,759		)	—		(128		)
Purchases	3,163			34			—		—
Settlements	(1,604		)	205			—		145
Balance at end of period	$	938		$	(1,272	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	1,455		$	(1,537	)	$	—	$	—

Gains and losses (realized and unrealized) for Level 3 fair value measurements included in earnings are reported in operating revenues and cost of energy as follows:

	PNMR						PNM
	September 30,						September 30,
	2011			2010			2011		2010
Three Months Ended	(In thousands)
Gains (losses) included in earnings:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	(5,025		)	(945		)	—		—
Total	$	(5,025	)	$	(945	)	$	—	$	—
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	589			(994		)	—		—
Total	$	589		$	(994	)	$	—	$	—
Nine Months Ended
Gains (losses) included in earnings:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	201			(1,759		)	—		(128		)
Total	$	201		$	(1,759	)	$	—	$	(128	)
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	1,455			(1,537		)	—		—
Total	$	1,455		$	(1,537	)	$	—	$	—

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

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 Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended September 30, 2011	(In thousands)
Operating revenues	$	323,760		$	54,787		$	170,999		$	(48	)	$	549,498
Intersegment revenues	—			12,196			—			(12,196		)	—
Total revenues	323,760			66,983			170,999			(12,244		)	549,498
Cost of energy	108,708			10,307			144,035			(12,196		)	250,854
Gross margin	215,052			56,676			26,964			(48		)	298,644
Other operating expenses	102,080			22,451			25,076			(1,617		)	147,990
Depreciation and amortization	25,058			12,674			346			4,292			42,370
Operating income (loss)	87,914			21,551			1,542			(2,723		)	108,284
Interest income	3,770			1			29			(52		)	3,748
Other income (deductions)	(5,573		)	313			(115		)	(1,664		)	(7,039		)
Net interest charges	(18,487		)	(7,276		)	(249		)	(5,112		)	(31,124		)
Segment earnings (loss) before income taxes	67,624			14,589			1,207			(9,551		)	73,869
Income taxes (benefit)	25,052			5,721			594			(5,403		)	25,964
Segment earnings (loss)	42,572			8,868			613			(4,148		)	47,905
Valencia non-controlling interest	(4,111		)	—			—			—			(4,111		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	38,329		$	8,868		$	613		$	(4,148	)	$	43,662
Nine Months Ended September 30, 2011
Operating revenues	$	797,232		$	150,175		$	405,485		$	(145	)	$	1,352,747
Intersegment revenues	—			30,608			—			(30,608		)	—
Total revenues	797,232			180,783			405,485			(30,753		)	1,352,747
Cost of energy	279,419			30,719			303,285			(30,609		)	582,814
Gross margin	517,813			150,064			102,200			(144		)	769,933
Other operating expenses	329,502			67,431			67,693			(7,172		)	457,454
Depreciation and amortization	71,691			33,662			987			12,775			119,115
Operating income (loss)	116,620			48,971			33,520			(5,747		)	193,364
Interest income	12,052			1			63			(106		)	12,010
Other income (deductions)	4,129			887			(494		)	(4,913		)	(391		)
Net interest charges	(54,593		)	(21,880		)	(535		)	(15,243		)	(92,251		)
Segment earnings (loss) before income taxes	78,208			27,979			32,554			(26,009		)	112,732
Income taxes (benefit)	26,574			10,845			11,833			(12,046		)	37,206
Segment earnings (loss)	51,634			17,134			20,721			(13,963		)	75,526
Valencia non-controlling interest	(10,764		)	—			—			—			(10,764		)
Subsidiary preferred stock dividends	(396		)	—			—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	40,474		$	17,134		$	20,721		$	(13,963	)	$	64,366
At September 30, 2011:
Total Assets	$	3,936,468		$	1,041,613		$	274,741		$	119,818		$	5,372,640
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310
Additions to utility and non-utility plant included in accounts payable	$	6,811		$	4,672		$	106		$	253		$	11,842

	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended September 30, 2010	(In thousands)
Operating revenues	$	304,268		$	49,709		$	149,729		$	(53	)	$	503,653
Intersegment revenues	—			11,495			—			(11,495		)	—
Total revenues	304,268			61,204			149,729			(11,548		)	503,653
Cost of energy	98,030			9,276			119,358			(11,495		)	215,169
Gross margin	206,238			51,928			30,371			(53		)	288,484
Other operating expenses	102,452			20,711			23,952			(3,019		)	144,096
Depreciation and amortization	23,111			11,594			210			4,065			38,980
Operating income (loss)	80,675			19,623			6,209			(1,099		)	105,408
Interest income	4,523			—			3			(27		)	4,499
Equity in net earnings (loss) of Optim Energy	—			—			—			2,495			2,495
Other income (deductions)	1,902			88			(66		)	(1,603		)	321
Net interest charges	(18,011		)	(7,661		)	(364		)	(5,281		)	(31,317		)
Segment earnings (loss) before income taxes	69,089			12,050			5,782			(5,515		)	81,406
Income taxes (benefit)	25,926			4,721			2,225			(4,059		)	28,813
Segment earnings (loss)	43,163			7,329			3,557			(1,456		)	52,593
Valencia non-controlling interest	(3,909		)	—			—			—			(3,909		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	39,122		$	7,329		$	3,557		$	(1,456	)	$	48,552
Nine Months Ended September 30, 2010
Operating revenues	$	777,864		$	131,233		$	384,034		$	(266	)	$	1,292,865
Intersegment revenues	—			30,717			—			(30,717		)	—
Total revenues	777,864			161,950			384,034			(30,983		)	1,292,865
Cost of energy	264,102			27,383			296,469			(30,716		)	557,238
Gross margin	513,762			134,567			87,565			(267		)	735,627
Other operating expenses	318,353			58,534			65,652			(10,109		)	432,430
Depreciation and amortization	68,887			31,728			683			12,336			113,634
Operating income (loss)	126,522			44,305			21,230			(2,494		)	189,563
Interest income	14,538			1			16			53			14,608
Equity in net earnings (loss) of Optim Energy	—			—			—			(5,714		)	(5,714		)
Other income (deductions)	11,069			717			(164		)	(4,544		)	7,078
Net interest charges	(54,473		)	(23,483		)	(1,062		)	(15,470		)	(94,488		)
Segment earnings (loss) before income taxes	97,656			21,540			20,020			(28,169		)	111,047
Income taxes (benefit)	34,748			8,461			7,363			(13,207		)	37,365
Segment earnings (loss)	62,908			13,079			12,657			(14,962		)	73,682
Valencia non-controlling interest	(10,305		)	—			—			—			(10,305		)
Subsidiary preferred stock dividends	(396		)	—			—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	52,207		$	13,079		$	12,657		$	(14,962	)	$	62,981
At September 30, 2010:
Total Assets	$	3,812,829		$	1,004,785		$	259,621		$	303,574		$	5,380,809
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310

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Fair Value of Derivative and Other Financial Instruments, Debt Maturities (Details) (USD $) In Thousands	Sep. 30, 2011
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]
Available-for-sale debt securities, Within 1 year	$ 683
Available-for-sale debt securities, After 1 year through 5 years	20,259
Available-for-sale debt securities, After 5 years through 10 years	10,740
Available-for-sale debt securities, Over 10 years	39,705
Available-for-sale debt securities	71,387
Held-to-maturity Securities, Debt Maturities, Fair Value [Abstract]
Held-to-maturity debt securities, Due within 1 year	0
Held-to-maturity debt securities, After 1 year through 5 years	123,206
Held-to-maturity debt securities, After 5 years through 10 years	3,370
Held-to-maturity debt securities, Over 10 years	0
Held-to-maturity debt securities	126,576
Public Service Company of New Mexico [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value [Abstract]
Held-to-maturity debt securities, Due within 1 year	0
Held-to-maturity debt securities, After 1 year through 5 years	112,083
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities, Over 10 years	0
Held-to-maturity debt securities	$ 112,083

XML

Fair Value of Derivative and Other Financial Instruments, Derivative Balance Sheet Information (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	$ 3,716	$ 15,999
Commodity derivative instruments, Deferred charges	247	5,264
Commodity derivative instruments, Current liabilities	(1,746)	(31,407)
Commodity derivative instruments, Long-term liabilities	(1,913)	(12,831)
Public Service Company of New Mexico [Member] | Maximum [Member] | Commodity Contract [Member] | Fuel and Purchased Power Adjustment Clause [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Deferred charges	100
Commodity derivative instruments, Long-term liabilities	(100)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Fuel and Purchased Power Adjustment Clause [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	800	600
Commodity derivative instruments, Current liabilities	(400)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Economic hedges [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	3,716	1,443
Commodity derivative instruments, Deferred charges	247	0
Commodity derivative instruments, Assets	3,963	1,443
Commodity derivative instruments, Current liabilities	(1,746)	(3,110)
Commodity derivative instruments, Long-term liabilities	(1,913)	(2,009)
Commodity derivative instruments, Liabilities	(3,659)	(5,119)
Commodity derivative instruments, Net	304	(3,676)
Commodity Contract [Member] | Economic hedges [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	32,168	15,999
Commodity derivative instruments, Deferred charges	9,064	5,264
Commodity derivative instruments, Assets	41,232	21,263
Commodity derivative instruments, Current liabilities	(41,018)	(31,407)
Commodity derivative instruments, Long-term liabilities	(16,373)	(12,831)
Commodity derivative instruments, Liabilities	(57,391)	(44,238)
Commodity derivative instruments, Net	(16,159)	(22,975)
Trading transactions [Member]
Derivatives, Fair Value [Line Items]
Number of Derivative Transactions	0	0
Cash flow hedges [Member]
Derivatives, Fair Value [Line Items]
Number of Derivative Transactions	0	0
Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	3,716	1,443
Commodity derivative instruments, Deferred charges	247	0
Commodity derivative instruments, Current liabilities	(1,746)	(3,110)
Commodity derivative instruments, Long-term liabilities	$ (1,913)	$ (2,009)

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Significant Accounting Policies and Responsibility for Financial Statements (Policies)

9 Months Ended

Sep. 30, 2011

Accounting Policies [Abstract]

Consolidation, Policy [Policy Text Block]

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. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. PNMR entered into an agreement to sell First Choice on September 23, 2011 and the sale was completed on November 1, 2011. See Note 16. In addition, PNM consolidates the PVNGS Capital Trust and Valencia. PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are allocated to the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include transmission and distribution services; lease, interest, and income tax sharing payments; and dividends paid on common stock. Intercompany transactions and balances have been eliminated, as appropriate. See Note 12.

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

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 is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. The Company is also involved in various legal 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 proceedings on its financial position, results of operations, or cash flows. It is the Company's policy to accrue for expected liabilities in accordance with GAAP when it is probable that a liability has been incurred and the amount to be incurred is reasonably estimable. 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, although the outcome of litigation, investigations, and other legal proceedings is inherently uncertain.

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, is not reasonably estimable. 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 subject to the known uncertainty of litigation. The Company has recorded 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.

Additional information concerning commitments and contingencies is contained in Note 16 of Notes to Consolidated Financial Statements in the 2010 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, and the DOE is required 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. 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. Such estimate reflects the impact of the extension of the PVNGS operating licenses discussed in Note 13 below. PNM accrues these costs as a component of fuel expense, meaning that the charges are accrued as the fuel is consumed. At September 30, 2011 and December 31, 2010, PNM recorded interim storage costs of $14.5 million and $14.8 million in other deferred credits.

The Clean Air Act

Regional Haze

EPA has established rules addressing regional haze and guidelines for BART determinations. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. In particular, the rules define how an SO₂ emissions trading program developed by the Western Regional Air Partnership, a voluntary organization of western states, tribes, and federal agencies, can be used by western states. New Mexico will be participating in the SO₂ program, which is a trading program that will be implemented if SO₂ reduction milestones are not met.

SJGS

In November 2006, the NMED requested a BART analysis for NOx and particulates for each of the four units at SJGS. PNM submitted its analysis to the NMED in June 2007, recommending against installing additional pollution control equipment on any of the SJGS units beyond those planned at that time, the installation of which was completed in March 2009. PNM subsequently provided additional data in response to requests from the NMED. On June 21, 2010, the NMED filed its proposed regional haze SIP with the EIB. The NMED filing included a finding by the NMED that BART for NOx at SJGS is a technology known as “selective catalytic reduction” (“SCR”) plus “sorbent injection.” PNM disagreed with this proposed BART determination.

As part of its 2007 submission, PNM identified additional control technology alternatives, including SCR, to already planned pollution control equipment upgrades and evaluated the feasibility of these technologies for the purpose of reducing visibility impacts in accordance with EPA's "Guidelines for BART Determinations under the Regional Haze Rules" (“BART Guidelines”). PNM concluded that SCR was not appropriate as BART. In 2010, using EPA's BART Guidelines, PNM estimated the installation of SCR technology at SJGS would cost approximately $750 million to $1 billion for the entire station, of which PNM's share would be 46.3% based on its SJGS ownership percentage. The SCR technology would also increase operating costs at SJGS.

In July 2011, PNM received a detailed conceptual design and cost estimate for installation of SCR at SJGS from an independent engineering design firm. Unlike the analysis prepared in 2007, the July 2011 analysis is based on quantity take-off estimates from the conceptual design that this engineering firm was in the process of developing. A cost estimate based on this work was submitted to EPA on July 20, 2011. Although there are certain differences between the two analyses, the July 2011 cost estimate is consistent with PNM's earlier BART analysis cost estimate range and continues to support PNM's contention that EPA's SCR cost estimates are unrealistically low.

Under a consent decree it signed with WildEarth Guardians in 2010, EPA was required to issue a proposed FIP regarding interstate transport for certain states, including New Mexico, by November 11, 2010, which was later extended to December 22, 2010, if no proposed SIP had been submitted. Interstate transport requires states to have adequate provisions to avoid interfering with the air quality implementation plans developed in other states. A separate section of the CAA regulates “regional haze,” which requires states to identify certain facilities that impact visibility in the 156 Class I areas (national parks and wilderness areas). Once identified, states determine the types of emission controls that should be installed as BART at those facilities to reduce the visibility impairing pollutants. EPA Region 6 issued a proposed interstate transport FIP, which was published in the Federal Register on January 5, 2011. The proposed FIP also included a regional haze BART determination for NOx controls at SJGS that requires SCR installation on all four units within three years of the final order, rather than the five-year implementation schedule the regional haze rules generally allow and that EPA proposed for Four Corners. The proposed FIP did not require sorbent injection. The proposed FIP provided for a proposed emission limit for NOx at SJGS of 0.05 pounds per MMBTU, whereas EPA's proposed emission limit for NOx at Four Corners is 0.098 pounds per MMBTU. The public comment period on the proposed FIP ended on April 4, 2011. The deadline for issuance of the final FIP was extended to August 5, 2011 pursuant to an agreement between EPA and WildEarth Guardians.

NMED withdrew its June 21, 2010 proposed regional haze SIP on December 17, 2010. On February 28, 2011, the NMED filed a new petition with the EIB to consider both an interstate transport SIP and a regional haze SIP. Among other things, the draft regional haze SIP concludes that selective non-catalytic reduction (“SNCR”) controls are regional haze BART for SJGS. SNCR controls meet EPA's presumptive NOx BART limit of 0.23 pounds per MMBTU for wall-fired boilers burning sub-bituminous coal. The proposed SIP required installation of SNCR controls within five years. PNM estimates the installation of SNCR technology at SJGS would cost approximately $77 million for the entire station, of which PNM's share would be 46.3%. The EIB approved the NMED's proposed regional haze and interstate transport SIPs in June 2011 upon conclusion of public hearings and the Governor of New Mexico submitted the SIPs to EPA in June 2011, which EPA received in July 2011.

PNM filed extensive technical and legal comments on the proposed FIP with EPA, including a statement in support of the then-draft SIP. As noted, the EIB approved SIP was received by EPA in July 2011. PNM believed that EPA must consider that SIP under the CAA, which requires EPA to give deference to a state's conclusions with respect to its air quality. Only the interstate transport rule was subject to the August 5, 2011 court-ordered deadline for a final FIP. In order to meet that deadline and at the same time give due consideration to the SIP, the Governor of New Mexico requested that EPA finalize the FIP associated with the interstate transport rule by August 5, 2011 and stay any action on the proposed FIP for regional haze until New Mexico's SIP revisions had been fully considered and either approved or disapproved. Nevertheless, on August 5, 2011, EPA issued its final FIP on both interstate transport and regional haze, which requires installation of SCR technology at SJGS and allows for a five-year implementation schedule. The final FIP was published in the Federal Register in August 2011 and became effective on September 21, 2011. The final FIP provides for an emission limit for NOx at SJGS of 0.05 pounds per MMBTU, including startup, shutdown, and malfunction emissions which were not included in the draft FIP. On September 16, 2011, PNM filed a Petition for Review of EPA's final FIP determination in the United States Court of Appeals for the Tenth Circuit. On the same day and pursuant to the Administrative Procedures Act, PNM filed a Request for a Stay of the effective date of the final BART determination pending judicial review with EPA. PNM filed a Petition for Reconsideration of the rule and a Request to Stay the effective date of the final BART FIP under the CAA with EPA on October 21, 2011. Neither the Petition in the Tenth Circuit, nor the Petition for Reconsideration by EPA delays the implementation timeframe unless a stay is granted. WildEarth Guardians filed a separate appeal against EPA challenging the five-year, rather than three-year, implementation schedule. PNM was granted leave to intervene in that appeal. WildEarth Guardians, Dine Citizens against Ruining our Environment, National Parks Conservation Association, New Energy Economy, San Juan Citizens Alliance, and Sierra Club sought, and were granted, leave to intervene in PNM's appeal. On October 21, 2011, the Governor of New Mexico and the NMED filed a Petition for Review of EPA's final FIP determination in the Tenth Circuit and a Petition for Reconsideration of the rule with EPA.

As stated above, PNM believes that SCR technology is not appropriate for BART at SJGS and that the state's SIP which calls for SNCR provides reasonable progress towards visibility improvements required under the CAA and EPA rules. EPA indicated on August 5, 2011, that it would continue to review the state's SIP but that EPA had already evaluated SNCR as part of the FIP and had ruled SNCR out as BART for San Juan.

Although PNM is challenging EPA's decision, the five-year compliance deadline requires PNM to take immediate steps to commence the installation of SCR, which is a large construction project requiring extensive advance planning. Accordingly, PNM plans to issue as soon as possible a RFP to prospective bidders for the installation of SCR. In connection with this process, PNM has, with the assistance of a leading engineering firm, further refined the conceptual design and cost estimates for the installation of SCR at SJGS. The current estimate for such construction is in the range of approximately $749 million to $897 million, exclusive of AFUDC, which at the lower range would be approximately $38 million and at the upper range would be approximately $45 million.

PNM will seek recovery from its ratepayers of all costs that may ultimately be incurred as a result of the final FIP. While PNM cannot accurately predict the impact of these requirements on PNM's ratepayers until requirements, if any, are finalized, it estimates that the installation of SCR controls would cost the average residential PNM customer up to approximately $85 for the first yearwith slowly declining costs during the period of depreciation of the SCR and that costs to businesses would be higher.

On January 19, 2011, multiple parties filed with EPA a NOI to sue under the CAA for EPA's failure to promulgate a FIP within two years of a finding that certain states, including New Mexico, had failed to make all or part of a required regional haze SIP submittal. The NOI alleges that the deadline for final promulgation of regional haze FIPs or full approval of regional haze SIPs was January 15, 2011. The same parties also filed a separate NOI to sue under the CAA for EPA's failure to take final action on SIP submissions by multiple states, including New Mexico, within 18 months of receipt of submission.

PNM is unable to predict the ultimate outcome of these matters or what, if any, additional pollution control equipment will ultimately be required or approved for installation for SJGS. If additional equipment is required and/or final requirements result in additional operating costs to be incurred, PNM believes that its access to the capital markets are sufficient to be able to finance the installation and that equipment and financing costs should be recoverable through the ratemaking process and would seek recovery of them. However, PNM can provide no assurance that all such amounts will be recovered from ratepayers. It is possible thatrequirements to comply with the final BART determinations, 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 of individual participants to continue participation in the plant.

Four Corners

EPA Region 9 previously requested that APS, as the operating agent for Four Corners, perform a BART analysis for Four Corners. APS submitted an analysis to EPA concluding that certain combustion control equipment constitutes BART for Four Corners. Based on the analyses and comments received through EPA's rulemaking process, EPA will determine what it believes constitutes BART for Four Corners.

On October 6, 2010, EPA issued its proposed BART determination for Four Corners. The rule, as proposed, would require the installation of SCR as post-combustion controls on each of Units 1-5 at Four Corners to reduce NOx emissions. As previously disclosed, PNM estimates its total costs could be up to approximately $69.0 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. EPA proposed a 10% stack opacity limitation for all five units and a 20% opacity limitation on certain fugitive dust emissions, although the proposed fugitive dust provision is unrelated to BART.

SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the coal-fired plant. On November 8, 2010, 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. Completion of the purchase by APS, which is expected to occur in the second half of 2012, is subject to the receipt of various regulatory approvals. Closing is also conditioned on the execution of a new coal supply contract for the lease renewal period described in Note 13 and other conditions. Pursuant to an agreement among the Four Corners participants, the other participants had a right of first refusal to purchase shares of SCE's interests proportional to their current ownership percentages. The exercise of this purchase right expired on March 8, 2011 and neither PNM nor any of the other participants exercised this right. APS has announced that, if APS's purchase of SCE's interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2, and 3 at the plant (PNM has no ownership interest in Four Corners Units 1, 2, and 3).

On November 24, 2010, APS submitted a letter to EPA proposing an alternative to EPA's October 2010 BART proposal. Specifically, APS proposed to close Four Corners Units 1, 2, and 3 by 2014 and to install post-combustion pollution controls for NOx on Units 4 and 5 by the end of 2018, provided that EPA agrees to a contemporaneous resolution of Four Corners' obligations or liability, if any, under the regional haze and reasonably attributable visibility impairment programs, the NSR program, and NSPS programs of the CAA.

On February 10, 2011, EPA signed a Supplemental Notice Requesting Comment, related to the BART rulemaking for Four Corners. In the Supplemental Notice, EPA proposed to find that a different alternative emission control strategy, based upon APS's November 2010 proposal, would achieve more progress than EPA's October 2010 BART proposal. The Supplemental Notice proposes that Units 1, 2, and 3 would close by 2014, post-combustion pollution controls for NOx would be installed on Units 4 and 5 by July 31, 2018, and the NOx emission limitation for Units 4 and 5 would be 0.098 lbs/MMBtu, rather than the 0.11 lbs/MMBtu proposed by EPA in October 2010. EPA proposals are subject to public comment. On July 15, 2011, various environmental groups filed a NOI to sue EPA because it failed to promulgate regional haze FIPs for Four Corners and Navajo Generating Station. PNM is not an owner of Navajo Generating Station. The NOI states that EPA has failed to fulfill its nondiscretionary duty under the CAA to submit a BART determination for the plants without unreasonable delay. The CAA requires parties to give EPA 180 days' notice before commencing a lawsuit based on allegations that EPA unreasonably delayed performance of a nondiscretionary act.

In addition, on February 16, 2010, a group of environmental organizations filed a petition with the DOI and DOA requesting those agencies to certify to EPA that visibility impairment in sixteen national park and wilderness areas is reasonably attributable to emissions from Four Corners and other plants. If the agencies certify impairment, EPA is required to evaluate and, if necessary, determine BART for Four Corners under a different haze program known as “Reasonably Attributable Visibility Impairment.” On January 19, 2011, a similar group of environmental organizations filed a lawsuit against the DOI and DOA, alleging among other things that the agencies failed to act on the February 2010 petition “without unreasonable delay” and requesting the court to order the agencies to act on the petition within 30 days. On June 30, 2011, the court issued its opinion dismissing the plaintiffs' claims explaining that because the DOI and DOA reached a “definitive decision” to deny the plaintiffs' petitions, the court is unable to grant further relief to the plaintiffs and, therefore, their claims must be dismissed as moot.

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, the result of the lawsuit mentioned above, 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 proposed BART determination for Four Corners. As proposed, the participant owners of Four Corners will have five years after EPA issues its final determination to achieve compliance with the BART requirements. PNM is unable to predict the ultimate outcome of this matter.

Ozone Non-Attainment

In March 2009, the NMED published its draft recommendation of area designations for the 2008 revised ozone national ambient air quality standard ("NAAQS"). The draft recommended that San Juan County, New Mexico be designated as non-attainment for ozone. SJGS is situated in San Juan County. However, the NMED subsequently determined that the monitor indicating high ozone levels was not reliable and did not recommend to EPA that San Juan County be designated as non-attainment. On January 6, 2010, EPA announced it would strengthen the 8-hour ozone standard by setting the standard in a range of 0.060-0.070 parts per million (“ppm”). EPA had intended to establish a new ozone standard by July 31, 2011. However, on September 2, 2011, President Obama requested that the EPA administrator withdraw the agency's proposed rule that would have replaced the existing ozone NAAQS.   The President in his release stated that work is already underway to reconsider the ozone standard in 2013.  Depending upon where the standard is set in the 2013 reconsideration of the ozone standard, San Juan County could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county back into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone in the presence of sunlight. As a result, SJGS could be required to put on additional NOx controls. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter 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 the SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes a provision whereby stipulated penalties are assessed 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 for each quarter. Over the past several years, PNM has also submitted reports addressing mercury and NOx emission controls for SJGS as required by the Consent Decree. Plaintiffs and NMED rejected PNM's reports. PNM disputes the validity of the rejection of the reports. On May 17, 2010, PNM filed a petition with the federal district court seeking a judicial determination on the dispute relating to PNM's mercury controls. NMED and plaintiffs seek to require PNM to implement mercury controls that PNM estimates would increase annual mercury control costs for the entire station by as much as $42 million (for a total annual mercury control cost of $47 million). The court held a status conference on November 29, 2010 for purposes of establishing the appropriate process for resolution of the outstanding disputes related to this matter and to discuss other issues raised in PNM's petition and has tentatively selected a special master to evaluate the technical arguments in the case. PNM cannot predict the outcome of this matter.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government as well as a lease from the Navajo Nation. The Navajo Acts, enacted in 1995 by the Navajo Nation, 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, Window Rock District, challenging the applicability of the Navajo Acts to Four Corners. The District Court stayed these proceedings pursuant to a request by the parties and the parties are seeking to negotiate a settlement.

In 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations.Each of the Four Corners participants filed a petition with the Navajo Nation Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the outcome of the settlement negotiations mentioned above.

In May 2005, APS and the Navajo Nation signed a Voluntary Compliance Agreement resolving the dispute regarding 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.

The Company cannot currently predict the outcome of these matters or the range of their potential impacts.

Section 114 Request

On April 6, 2009, APS received a request from EPA under Section 114 of the CAA seeking detailed information regarding projects at and operations of Four Corners. This request is part of an enforcement initiative that EPA has undertaken under the CAA. EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the CAA. Other electric utilities have received and responded to similar Section 114 requests, and several of them have been subject to notices of violation and lawsuits by EPA. 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 New Source Review

On May 7, 2010, APS received a NOI to sue from EarthJustice, on behalf of several environmental organizations, related to alleged violations of the CAA at Four Corners.  The NOI alleges NSR related violations and NSPS violations.  Under the CAA, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit.  Within that 60-day time period, EPA may step in and file a lawsuit regarding the allegations. If EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in EPA's lawsuit, if it so desires.  The 60-day period lapsed in July 2010, and EPA did not take any action. 

On September 2, 2011, APS received a second NOI to sue from EarthJustice, on behalf of the same environmental organizations. The September 2, 2011 notice is virtually identical to the May 2010 Notice and alleges violations of the NSR and NSPS programs.

On October 3, 2011, EarthJustice filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants, except PNM (EarthJustice filed suit against PNMR, which is not a Four Corners participant), alleging violations of the PSD provisions of the CAA. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. APS is evaluating the lawsuit. PNMR has not been served with this lawsuit.

On October 26, 2011, APS received a third NOI to sue from EarthJustice, on behalf of the same environmental organizations. The third notice is also virtually identical to the prior notices, as well as to the claims in the October 3, 2011 lawsuit.

At this time, PNM cannot predict the ultimate outcome of this matter. 

Review of New Sources and Modifications in Indian Country

Pursuant to its authority under the CAA, in June 2011, EPA finalized a FIP, which puts in place a pre-construction air permitting program for construction of new and modified small facilities and minor modifications of existing facilities in Indian country.  The FIP will require a source owner or operator to apply for a permit before building a new facility or modifying an existing one if it is determined that the proposed project will increase emissions above any of the minor NSR thresholds included in the rule.  Among other things, sources triggering the rule's source-specific permit requirements will be required to undergo a case-by-case control technology review and, potentially, an air impact quality analysis.  APS and PNM are currently evaluating the potential impact of this rule on Four Corners, which is located on Indian lands.

Endangered Species Act

On January 30, 2011, the Center for Biological Diversity, Dine Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit against the OSM and the DOI, alleging that OSM failed to engage in mandatory Endangered Species Act (“ESA”) consultation with the 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 requests 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.  PNM is not a party to the lawsuit. APS has intervened in the lawsuit and is evaluating the lawsuit to determine its potential impact on Four Corners operations.  PNM is unable to predict the ultimate outcome of this matter.

Cooling Water Intake Structures

EPA issued its proposed cooling water intake structures rule on April 20, 2011, which would provide national standards applicable to certain cooling water intake structures at existing power plants and other facilities pursuant to the Clean Water Act. The proposed standards are intended 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). To minimize impingement mortality, 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. To minimize entrainment mortality, 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 is subject to a public comment period, which was extended to August 18, 2011. EPA is expected to issue a final rule by July 2012. As proposed, existing facilities subject to the rule would have to comply with the impingement mortality requirements as soon as possible, but in no event later than eight years after the effective date of the rule, and would have to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. PNM and APS are performing analyses to determine the 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.

Santa Fe Generating Station

PNM and the NMED conducted investigations of gasoline and chlorinated solvent groundwater contamination detected beneath the site of the former Santa Fe Generating Station to determine the source of the contamination pursuant to a 1992 settlement agreement between PNM and the NMED.

PNM believes that the data compiled indicates observed groundwater contamination originated from off-site sources. However, to avoid a prolonged legal dispute, PNM entered into settlement agreements with the NMED under which PNM agreed to install a remediation system to treat water from a City of Santa Fe municipal supply well and install an additional extraction well and two new monitoring wells to address gasoline contamination in the groundwater at and in the vicinity of the site. PNM will continue to operate the remediation facilities until the groundwater meets applicable federal and state standards or until such time as the NMED determines that additional remediation is not required, whichever is earlier. The well continues to operate and meets federal drinking water standards. PNM is not able to assess the duration of this project.

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. The Company is unable to predict the outcome of this matter.

Coal Combustion Waste Disposal

Regulation

SJCC currently disposes of CCBs consisting of fly ash, bottom ash, and gypsum from SJGS 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 at the mine with federal oversight by the OSM. APS currently 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 the Four Corners plant is regulated by EPA and the New Mexico State Engineer's Office. 

On May 4, 2010, EPA issued a proposed rulemaking to regulate CCBs.  The proposal asks for public comment on two approaches for regulating CCBs. One option is to regulate CCBs under Subtitle C of the RCRA as a hazardous waste which allows EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs under RCRA Subtitle D as a non-hazardous waste. This provides 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. EPA has indicated that it will work with the OSM to develop federal regulations for placement of CCBs in minefill operations. The proposed rule also states that EPA and OSM will consider the recommendations of the National Research Council, which, at the direction of Congress, studied the health, safety, and environmental risks associated with the placement of CCBs in U.S. coal mines.  The 2006 report concluded that the “placement of coal combustion residues in mines as part of coal mine reclamation may be an appropriate option for the disposal of this material.” On June 21, 2010, EPA published the proposed rule in the Federal Register. The public comment period on the proposed rule ended November 19, 2010. A final rule regarding waste designation for coal ash is not expected from EPA before mid to late 2012.

The OSM had initially drafted a CCB mine placement rule in late summer 2008, but with the then-impending change in federal administration, the Office of Management and Budget at the White House returned the rule to OSM for re-submittal under the incoming administration. An OSM CCB rulemaking team has been formed to develop a proposed rule. OSM's draft rulemaking schedule targets an April 2012 publication in the Federal Register.

PNM advocates for the non-hazardous regulation of CCBs under Subtitle D of RCRA. PNM is encouraged by EPA's proposed decision to develop separate federal regulations in conjunction with the OSM's intent to develop regulations for mine placement of CCBs. PNM believes regulatory oversight for this matter should come from the OSM and state mining and mining reclamation agencies. In addition, PNM believes the decision by EPA to consider the conclusions of the National Research Council study in the development of federal regulations regarding placement of CCBs in minefilling operations is a prudent one. 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. 

Sierra Club Allegations

In December 2009, PNM and PNMR received a NOI to sue (“RCRA Notice”) under RCRA from the Sierra Club.  The RCRA Notice was also sent to all SJGS owners, to SJCC, which operates the San Juan Mine that supplies coal to SJGS, and to BHP. Additionally, PNM was informed that SJCC and BHP received a separate NOI to sue under the Surface Mine Control and Reclamation Act ("SMCRA") from the Sierra Club. On April 8, 2010, the Sierra Club filed suit in the U.S. District Court for the District of New Mexico against PNM, PNMR, SJCC, and BHP. In the suit, the Sierra Club alleges that activities at SJGS and the San Juan Mine are causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCBs at the San Juan Mine constitutes "open dumping" in violation of RCRA.  The claims under RCRA are asserted with respect to PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA, which are directed only against SJCC and BHP. The complaint requests judgment for the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCBs at the mine or to cease placement of CCBs at the mine; the imposition of civil penalties; and an award of plaintiff's attorney's fees and costs. On July 10, 2010, the Sierra Club filed an amended complaint that corrected some technical deficiencies in its original complaint. The factual allegations remained the same. The parties have agreed to a stay of the action, which the Court entered on August 27, 2010, to allow the parties to try to address Sierra Club's concerns. If the parties are unable to settle the matter, PNM is prepared to aggressively defend its position in the RCRA litigation.PNM and PNMR cannot predict the outcome of this matter or the range of potential outcomes at the present time.

Gila River Indian Reservation Superfund Site

In April 2008, EPA informed PNM that it may be a PRP in the Gila River Indian Reservation Superfund Site in Maricopa County, Arizona. PNM, along with SRP, APS, and EPE, owns a parcel of property on which a transmission pole and a portion of a transmission line are located. The property abuts the Gila River Indian Community boundary and, at one time, may have been part of an airfield where crop dusting took place. EPA has settled the matter with the PRPs for past cleanup-related costs involving contamination from the crop dusting. PNM's share of the settlement was less than $0.1 million.

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, 2011 and December 31, 2010, prepayments for coal, which are included in other current assets, amounted to $17.8 million and $30.9 million. SJCC holds certain federal, state, and private coal leases under an underground coal sales agreement pursuant to which it will supply processed coal for operation of the SJGS through 2017. The coal agreement is a cost plus contract. SJCC is reimbursed for all costs for mining and delivering the coal plus an allocated portion of administrative costs. In addition, SJCC 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 approximately 44.2 million tons of coal during its remaining term, which would supply substantially all the requirements of the SJGS through approximately 2017.

APS purchases all of Four Corners' coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016 with pricing determined using an escalating base-price. APS is currently in discussions with the coal supplier regarding post-2016 coal supply for Four Corners.

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 most recent estimates, the final costs of mine reclamation, net of contract buyout costs paid to SJCC and reclamation payments made through September 30, 2011, are estimated to be $53.4 million for the surface mines at both SJGS and Four Corners and $21.7 million for the underground mine at SJGS, in future dollars. PNM made payments against the surface mine liability of $1.3 million and $3.6 million during the three and nine months ended September 30, 2011 and $0.9 million and $3.5 million during the three and nine months ended September 30, 2010. As of September 30, 2011 and December 31, 2010, obligations of $23.7 million and $25.0 million for surface mine reclamation and $3.0 million and $2.8 million for underground mining activities were recorded in other deferred credits.

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 and has since been on-site. On September 12, 2011, SJCC informed PNM that the fire was extinguished and continues to report that all measurements from the area of the fire continue to suggest the fire is extinguished. However, MSHA requires sealing the incident area and confirming a noncombustible environment before MSHA will allow re-entry of the mine. SJCC informed PNM that MSHA approved a sealing plan on October 6, 2011. SJCC has indicated to PNM that it believes the mine’s longwall equipment has experienced only minor damage, if any, and currently estimates being able to restart longwall mining operations approximately April 1, 2012.

PNM continues to actively monitor developments at the mine and evaluate the availability of coal supply. As of September 9, 2011, there were inventories of previously mined coal available to supply the fuel requirements of SJGS for approximately eight and one-half months at forecasted consumption before the disruption. Production from continuous miner sections may be possible before the longwall mining operations resume, perhaps as soon as mid-November, and coal sourced from other mines is being considered to supplement inventories. SJCC has also reported it is implementing cost savings measures during the mine disruption and PNM is working with SJCC to identify cost-saving opportunities to mitigate the impact of the incident.

PNM anticipates that as the cost of the mine recovery flows through the cost-reimbursable component of the coal supply agreement, it would recover the portion of such costs attributable to its customers subject to New Mexico regulation through its FPPAC. PNM is unable at this time to predict when operations will resume at the mine. Based on information PNM has received from SJCC to date, PNM does not expect the mine fire to have a material effect on its financial condition, results of operations, or cash flows due to the inventories of previously mined coal available to supply SJGS. However, if the mine is shut down longer than currently anticipated, 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.

PVNGS Liability and Insurance Matters

The PVNGS participants have insurance for public liability exposure for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, the PVNGS participants maintain the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 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. The maximum assessment per reactor under the program for each nuclear incident is $117.5 million, subject to an annual limit of $17.5 million per incident, to be periodically adjusted for inflation. Based on PNM's 10.2% interest in the three PVNGS units, PNM's maximum potential assessment per incident for all three units is $36.0 million, with an annual payment limitation of $5.4 million.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for property 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. The property damage and decontamination coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). PNM is subject to retrospective assessments under all NEIL policies if NEIL's losses in any policy year exceed accumulated funds. The maximum amount PNM could incur under the current NEIL policies totals $5.8 million for each retrospective assessment declared by NEIL's Board of Directors due to losses. The insurance coverage discussed in this and the previous paragraph is 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, Valencia, Afton, Luna, and Lordsburg. Water availability does not appear to be an issue for these plants at this time.

Severe drought, such as that which occurred during 2002 in the “four corners” region of New Mexico where SJGS and Four Corners are located, can affect the availability of these plants. In future years, if adequate precipitation is not received in the watershed that supplies the four corners region, the plants could be impacted. Consequently, PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines. 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. The current agreements run through December 31, 2012. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement on a long-term supplemental contract relating to water for SJGS and Four Corners with the Jicarilla Apache Nation that runs through 2016. Although the Company does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather situation or its ramifications, or how policy, regulations, and legislation may impact the Company 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 the next forty years.

PVNGS Water Supply Litigation

A summons was served on APS in 1986 that required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons. APS' rights and the rights of the other PVNGS participants to the use of groundwater and effluent at PVNGS are potentially at issue in this action. 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 both of 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 entitled “State of New Mexico v. United States, et al.”, in the District Court of San Juan County, New Mexico, to adjudicate all water rights in the San Juan River Stream System. PNM was made a defendant in the litigation in 1976. The action is expected to adjudicate water rights used at Four Corners and at SJGS. In 2005, the Navajo Nation and various parties announced a settlement of the Navajo Nation's surface water rights. On March 30, 2009, President Obama signed legislation confirming the settlement with the Navajo Nation.

The United States, the State of New Mexico, and the Navajo Nation have entered into a water rights settlement agreement and the court recently announced the initiation of a new phase of this adjudication. Under the terms of the settlement agreement, the Navajo 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 first in an expedited inter se proceeding. The Court held a scheduling conference on October 3, 2011 and has issued a scheduling order. A second scheduling conference will be conducted on January 9, 2012 to address discovery and the remainder of pretrial proceedings.

PNM's water rights in the San Juan Basin may be affected by the rights recognized as owned by the Navajo Nation in the settlement agreement, and PNM has elected to participate in this proceeding.  It is unknown at the present time how PNM will respond to the claims made in the proposed decrees, although the claims recognized as owned by the Navajo Nation in the settlement agreement and the proposed decrees constitute a significant portion of the water available from sources on the San Juan River and in the San Juan Basin.

The Company 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.

Conflicts at San Juan Mine Involving Oil and Gas Leaseholders

SJCC, through leases with the federal government and the State of New Mexico, owns coal interests with respect to the San Juan underground mine. Certain gas producers have leases in the area of the underground coal mine and have asserted claims against SJCC that its coal mining activities are interfering with gas production. SJCC has reached settlement with several gas leaseholders and has had success in court in defeating the claims of other claimants. Several other claims and potential claimants remain. PNM cannot predict the outcome of existing or future disputes between SJCC and gas leaseholders or the range of potential outcomes.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS. PNM argued that SPS' rates for sale of interruptible energy were excessive and that SPS had been overcharging PNM for deliveries of energy through its fuel cost adjustment clause practices. PNM also intervened in a complaint proceeding brought by other customers raising similar arguments relating to SPS' fuel cost adjustment clause practices (the “Golden Spread complaint proceeding”). Additionally, in November 2005, SPS filed an electric rate case at FERC proposing to unbundle and raise rates charged to customers effective July 2006. PNM intervened in the case and objected to the proposed rate increase. In September 2006, PNM and SPS filed a settlement agreement providing for resolution of issues relating to rates for sales of interruptible energy, but not resolving the fuel clause issues. In September 2008, FERC issued its order approving the settlement between PNM and SPS.

In April 2008, FERC issued its order in the Golden Spread complaint proceeding. FERC affirmed in part and reversed in part an ALJ's initial decision, which had, among other things, ordered SPS to pay refunds to PNM with respect to the fuel clause issues. FERC affirmed the decision of the ALJ that SPS violated its fuel cost adjustment clause tariffs. However, FERC shortened the refund period applicable to the violation of the fuel cost adjustment clause issues.PNM and SPS have filed petitions for rehearing and clarification of the scope of the remedies that were ordered and reversal of various rulings in the order. FERC has not yet acted upon the requests for rehearing or clarification and they remain pending further decision. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes.

Begay v. PNM et al

A putative class action was filed against PNM and other utilities on February 11, 2009 in the United States District Court in Albuquerque. 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. Plaintiffs, including an allottee association, make broad, general assertions 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.  The plaintiffs, who have sued the defendants for breach of fiduciary duty, seek a constructive trust. They have also included a breach of trust claim against the United States and its Secretary of the Interior.  PNM and the other defendants filed motions to dismiss this action. On March 31, 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. 

On May 10, 2010, Plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs ("BIA") and are attempting to perfect such appeal through the BIA's administrative process . PNM is participating 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.

Transmission Issues

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

During the first quarter of 2011, at the request of PNM and other southwestern utilities, NERC advised all transmission owners and transmission service providers they have delayed the implementation of portions of the MOD-029 methodology for "Flow Limited" paths 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 are expecting to file a Standards Action Request later this year as a follow-up to the NERC ruling.

On April 20, 2010, Cargill Power Markets, LLC (“Cargill”) filed a complaint with FERC, asserting that PNM improperly processed its transmission service queue and unfairly invalidated a transmission service request by Cargill. On July 29, 2010, FERC issued an order and established a schedule for hearing and settlement procedures. In its order, FERC determined that PNM had improperly invalidated a single Cargill transmission service request submitted on February 21, 2008 and set the issue for hearing to determine an appropriate remedy. However, the hearing is being held in abeyance by FERC to provide time for settlement negotiations under the oversight of a FERC settlement judge. On September 27, 2010, FERC granted rehearing for further consideration. On January 13, 2011, PNM and Cargill filed a settlement agreement with FERC in which PNM agreed to pay Cargill $0.2 million and put Cargill's transmission service request back into the queue. The settlement also left Cargill's and PNM's rehearing requests in place before FERC. One intervenor in the proceeding has contested the settlement. The settlement judge reported to FERC that the settlement is contested. The settlement is before FERC for its consideration. FERC has not yet acted upon the requests for rehearing or settlement. PNM is unable to predict the final outcome of this matter at FERC.

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Condensed Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Unrealized holding gains arising during the period, income tax (expense)	$ 1,123	$ (4,270)	$ (8,157)	$ (4,212)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	1,593	1,145	11,555	2,475
Pension liability adjustment, income tax (expense) benefit	(425)	0	176	147
Change in fair market value, income tax (expense)	123	(906)	441	(4,765)
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	(827)	5,319	(1,129)	13,546
Public Service Company of New Mexico [Member]
Unrealized holding gains arising during the period, income tax (expense)	1,123	(4,270)	(8,157)	(4,212)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	1,593	1,145	11,555	2,475
Pension liability adjustment, income tax (expense) benefit	(423)	0	9	147
Change in fair market value, income tax (expense)	0	(674)	0	(3,441)
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	0	3,525	(11)	8,735
Texas-New Mexico Power Company [Member]
Pension liability adjustment, income tax (expense) benefit	(1)	0	169	0
Change in fair market value, income tax (expense)	110	416	382	1,307
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	$ (850)	$ (92)	$ (1,052)	$ (297)

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Significant Accounting Policies and Responsibility for Financial Statements (Details) (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended		1 Months Ended						9 Months Ended			3 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Jul. 31, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Apr. 30, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Mar. 31, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Jan. 31, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Sep. 30, 2010 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Affiliated Entity [Member]	Sep. 30, 2010 Texas-New Mexico Power Company [Member] Affiliated Entity [Member]	Sep. 30, 2011 PNM Resources [Member]	Jun. 30, 2011 PNM Resources [Member]	Sep. 30, 2010 PNM Resources [Member]	Jun. 30, 2010 PNM Resources [Member]
Dividends Declared per Common Share (dollars per share)	$ 0.125	$ 0.125	$ 0.375	$ 0.375										$ 0.125	$ 0.125	$ 0.125	$ 0.125
Payments of Dividends, Common Stock					$ 3.6		$ 4.6		$ 39.1			$ 7.1	$ 5.8
Dividends, Common Stock						3.6		4.6		39.1		7.1	5.8
Common Stock Dividends Declared											$ 28.0

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2011

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

Stock-Based Compensation

Stock-Based Compensation

Information concerning stock-based compensation plans is contained in Note 13 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted in 2011 and awards of restricted stock have increased.

Stock Options

The following table summarizes activity in stock option plans for the nine months ended September 30, 2011:

	Shares		Weighted- Average Exercise Price		Aggregate Intrinsic Value			Weighted- Average Remaining Contract Life
Outstanding at beginning of period	3,948,262		$	18.33
Granted	—		$	—
Exercised	(254,394	)	$	10.99
Forfeited	(10,333	)	$	11.26
Expired	(102,338	)	$	24.96
Outstanding at end of period	3,581,197		$	18.68	$	8,950,188	(1)	5.12 years
Exercisable at end of period	3,045,556		$	21.97	$	6,011,541		4.60 years
Options available for future grant(2)	4,820,656

(1) At September 30, 2011, the exercise price of 1,923,608 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

(2) Includes shares available for grants of restricted stock.

The following table provides additional information concerning stock option activity:

	Nine Months Ended September 30,
Options for PNMR Common Stock	2011		2010
Weighted-average grant date fair value of options granted	$	—	$	3.05
Total fair value of options that vested (in thousands)	$	1,189	$	1,027
Total intrinsic value of options exercised (in thousands)	$	1,077	$	474

Restricted Stock and Performance Shares

The following table summarizes nonvested restricted stock activity for the nine months ended September 30, 2011:

Nonvested Restricted Stock	Shares		Weighted- Average Grant-Date Fair Value
Nonvested at beginning of period	237,021		$	9.24
Granted	308,985		$	13.10
Vested	(113,576	)	$	9.54
Forfeited	(1,000	)	$	13.67
Nonvested at end of period	431,430		$	11.92

Compensation expense for restricted stock and performance stock awards was determined based on the market price of PNMR stock on the date of grant reduced by the present value of future dividends, which will not be received during the vesting period, applied to the total number of shares that were anticipated to fully vest.

The following table provides additional information concerning restricted stock:

	Nine Months Ended
	September 30,
Nonvested Restricted Stock	2011			2010
Weighted-average grant date fair value of shares granted	$	13.10		$	9.37
Total fair value of shares that vested (in thousands)	$	1,084		$	1,365
Expected quarterly dividends per share	$	0.125		$	0.125
Risk-free interest rate	1.20		%	1.36		%

Beginning in 2009, the Company issued performance share agreements to certain executives that are based upon the Company achieving specified performance targets over periods of one to three years. The determination of the number of shares ultimately issued depends on the levels at which the performance criteria are achieved and cannot be determined until after the performance periods end. For the targets based only on 2010 performance, near optimal level was attained resulting in 88,913 shares being awarded in 2011, which will vest evenly from 2012 through 2014 and are included in the number of shares granted in the above table. Excluded from the above table is a maximum of 560,461 shares based on performance targets through 2013 that would be issued and vest upon issuance if all performance criteria are achieved and all executives remain eligible.

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Optim Energy

9 Months Ended

Sep. 30, 2011

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments Disclosure [Text Block]

Optim Energy

Information concerning Optim Energy is discussed in Note 22 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. In January 2007, Optim Energy was created by PNMR and ECJV, a wholly owned subsidiary of Cascade, to serve expanding U.S. markets, principally the areas of Texas covered by ERCOT. PNMR and ECJV each had a 50 percent ownership interest in Optim Energy, a limited liability company.

Impairment and Restructuring

Beginning in 2009 and continuing throughout 2010, Optim Energy was affected by adverse market conditions, primarily low natural gas and power prices. In addition to these adverse market conditions, reported sales of electric generating resources within the ERCOT market area were transacted at prices (per KW of generating capacity) that were substantially below the amounts recorded for the electric generating plants underlying PNMR’s investment in Optim Energy. Under GAAP, these factors were indicators of impairment that required an impairment analysis to be performed by PNMR of its investment in Optim Energy as of December 31, 2010. PNMR’s analysis indicated that its entire investment in Optim Energy was impaired and PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31, 2010, resulting in a pre-tax impairment loss of $188.2 million. In accordance with GAAP, PNMR has not recorded losses associated with its investment in Optim Energy in 2011 as PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources.

As a result of the adverse market conditions described above, PNMR (in collaboration with Optim Energy and ECJV) assessed various strategic alternatives relating to Optim Energy. On September 23, 2011, PNMR, ECJV, and Cascade agreed to restructure Optim Energy and ECJV made an equity contribution to Optim Energy in exchange for an increased ownership interest, which resulted in PNMR's ownership in Optim Energy being reduced from 50% to 1%. Optim Energy's debt is non-recourse to PNMR. As part of this transaction, PNMR did not make any equity contribution to Optim Energy nor will it be required to make any contribution in the future. From January 1, 2012 through December 31, 2013, ECJV has the option to purchase PNMR's 1% ownership interest in Optim Energy at fair market value and, if that option is not exercised, PNMR would have the option from June 30, 2014 to December 31, 2015 to sell its 1% ownership interest in Optim Energy to ECJV at fair market value. PNMR accounted for its investment in Optim Energy using the equity method of accounting until September 23, 2011 and is using the cost method thereafter. The fair value of PNMR's 1% ownership interest in Optim Energy was de minimis at September 30, 2011. PNMR Services Company has been providing certain corporate services to Optim Energy and will continue to provide certain services at least through the end of 2011 and after that with respect to certain tax matters.

Operational Information

As discussed above, PNMR fully impaired its investment in Optim Energy at December 31, 2010 and has not recognized losses of Optim Energy from January 1, 2011 through September 23, 2011 when PNMR ceased to account for its investment using the equity method of accounting. Accordingly, Optim Energy has no impact on PNMR's 2011 balance sheet, statement of earnings, and statement of cash flows. Therefore, summarized financial information for Optim Energy is not presented.

Optim Energy had net earnings (loss) of $7.6 million and $(6.8) million in the three months and nine months ended September 30, 2010. PNMR recognized net earnings (loss) from Optim Energy of $2.5 million and $(5.7) million in the three months and nine months ended September 30, 2010. Such amounts include amortization of a basis difference between PNMR's recorded investment in Optim Energy and 50 percent of Optim Energy’s equity.

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Capitalization

9 Months Ended

Sep. 30, 2011

Debt Disclosure [Abstract]

Capitalization

Capitalization

Information concerning financing activities is contained in Note 6 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

Short-term Debt

On October 31, 2011, PNMR entered into the PNMR Revolving Credit Facility, which has a financing capacity of $300.0 million, and PNM entered into the PNM Revolving Credit Facility, which has a financing capacity of $400.0 million. These new facilities expire on October 31, 2016, and include two one-year extension options, subject to approval by a majority of the lenders and, with respect to the PNM Revolving Credit Facility, regulatory approval. The new credit facilities replace the $517.0 million PNMR Facility and the $368.0 million PNM Facility, both of which would have expired in August 2012. The terms and conditions of the new facilities are substantially similar to the prior facilities. PNMR also has a local line of credit amounting to $5.0 million that expires in August 2012. TNMP has a revolving credit facility with financing capacity of $75.0 million under the TNMP Revolving Credit Facility that expires in December 2015. At September 30, 2011, the weighted average interest rate was 1.48% for the PNMR Facility and 0.88% for the PNM Facility. Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2011		2010
	(In thousands)
PNM – Revolving credit facility	$	257,000	$	190,000
TNMP – Revolving credit facility	—		—
PNMR
Revolving credit facility	32,000		32,000
Local lines of credit	—		—
	$	289,000	$	222,000

On November 1, 2011, PNMR utilized a portion of the proceeds from the sale of First Choice (see Note 16) to repay short-term debt incurred to finance the October 5, 2011 payment for the purchase of PNMR's Series A preferred stock described below, as well as all other PNMR borrowings under the PNMR Revolving Credit Facility. In addition, on November 1, 2011, PNMR loaned $63.8 million to PNM under their intercompany loan agreement and PNM repaid all borrowings under the PNM Revolving Credit Facility. At November 1, 2011, PNMR, PNM, and TNMP had $235.4 million, $394.8 million, and $74.7 million of availability under their respective revolving credit facilities and local lines of credit, including reductions of availability due to outstanding letters of credit. Total availability at November 1, 2011, on a consolidated basis, was $704.9 million for PNMR. At November 1, 2011, PNMR had invested cash of $166.7 million. PNM and TNMP had no such investments.

As of November 1, 2011, PNM and TNMP had $63.8 million and $5.4 million in borrowings from PNMR under their intercompany loan agreements, but had no such borrowings as of September 30, 2011.

Financing Activities

In March 2009, TNMP entered into and borrowed $50.0 million under a loan agreement with Union Bank, N. A. (the “2009 Term Loan Agreement”).  Through hedging arrangements, TNMP established fixed interest rates for the 2009 Term Loan Agreement of 6.05% for the first three years and 6.30% thereafter. In January 2010, the relationship was modified to reduce the fixed interest rate to 4.80% through March 31, 2012 and to 5.05% thereafter. This hedge was accounted for as a cash-flow hedge and the December 31, 2010 pre-tax fair value of $1.9 million was included in other current liabilities, except for $0.8 million included in other deferred credits, and in AOCI. Amounts reclassified from AOCI are included in interest charges. The fair value determinations were made using Level 2 inputs under GAAP and were determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.  

On September 30, 2011, TNMP entered into and borrowed $50.0 million under a Term Loan Credit Agreement (the "2011 Term Loan Agreement") with JPMorgan Chase Bank, N.A. Borrowings under this agreement must be repaid by June 30, 2014 and are secured by $50.0 million aggregate principal amount of first mortgage bonds of TNMP (the "Series 2011 A Bonds"). TNMP entered into hedging agreements whereby it effectively established fixed interest rates for such borrowing of 1.475% through March 30, 2014 and 1.985% thereafter, which is an effective rate of 3.566% over the life of the debt considering the amounts paid to exit the prior arrangements and enter into the new arrangements. The hedging obligations entered into in connection with the 2011 Term Loan Agreement are also secured by the Series 2011 A Bonds. This hedge is accounted for as a cash-flow hedge and had a zero fair value at September 30, 2011, using Level 2 inputs under GAAP. The 2011 Term Loan Agreement replaces the 2009 Term Loan Agreement. On September 30, 2011, TNMP repaid all amounts outstanding under the 2009 Term Loan Agreement and related hedging agreements.

On October 6, 2011, PNM priced a public offering of $160.0 million aggregate principal amount of its 5.35% Senior Unsecured Notes due 2021. The bonds were offered at 99.857% of face amount and the offering closed on October 12, 2011. The notes bear interest at a rate of 5.35% per annum, payable semi-annually on April 1 and October 1 of each year, beginning on April 1, 2012, and will mature on October 1, 2021. Proceeds from the offering were used to repay outstanding borrowings under the PNM Facility.

On October 24, 2011, PNMR commenced a cash tender offer to purchase up to $50.0 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015. The price PNMR is offering to pay for the notes is their principal amount plus a premium of up to 17%, depending on when the notes are tendered, plus accrued and unpaid interest. The tender offer is scheduled to expire on November 21, 2011. If the tender offer is successful, PNMR will use a portion of the proceeds from the sale of First Choice (see Note 16) to fund the purchase.

Convertible Preferred Stock

On September 23, 2011, PNMR entered into an agreement to purchase of all of its outstanding convertible preferred stock, Series A (the “Preferred Stock”) pursuant to a Sale and Purchase Agreement dated September 23, 2011 between PNMR and Cascade. Cascade owned all of the 477,800 outstanding shares of Preferred Stock, which were convertible into 4,778,000 shares of PNMR common stock. Upon signing, the agreement obligated PNMR to purchase the Preferred Stock at a 2% discount from a price determined by the daily volume weighted average price per share of PNMR's common stock for the ten trading days ending on September 30, 2011 times the number of shares of PNMR common stock into which the Preferred Stock was convertible. The purchase of the Preferred Stock closed on October 5, 2011 with PNMR paying Cascade $73.5 million. The difference between the purchase price and the $100.0 million carrying value of the Preferred Stock is reflected as an addition to common stock in the accompanying Condensed Consolidated Financial Statements. PNMR utilized a borrowing under its revolving credit facility to fund the purchase of the Preferred Stock. Such borrowing was repaid on November 1, 2011 with a portion of the proceeds from the sale of First Choice (see Note 16).

PNMR issued the Preferred Stock in November 2008. The Preferred Stock was entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the Preferred Stock had been converted into common stock. The Preferred Stock was entitled to vote on all matters voted upon by common stockholders, except for the election of the Board. In the event of liquidation of PNMR, preferred holders would have received a preference of $0.10 per common share equivalent. After that preference, common holders would have received an equivalent liquidation preference per share and all remaining distributions would have been shared ratably between common and preferred holders using the number of shares of common stock into which the Preferred Stock was convertible. The terms of the Preferred Stock resulted in it being substantially equivalent to common stock. Therefore, for earnings per share purposes the number of common shares into which the Preferred Stock was convertible was included in the weighted average number of common shares outstanding for periods prior to September 23, 2011. Similarly, dividends on the Preferred Stock were considered to be common dividends in the accompanying Condensed Consolidated Financial Statements.

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Pension and Other Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2011

Public Service Company of New Mexico [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

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

	Three Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	65		$	105		$	—	$	—
Interest cost	8,202			8,518			1,345			1,913			233		263
Long-term return on plan assets	(9,269		)	(9,339		)	(1,347		)	(1,393		)	—		—
Amortization of net loss	2,302			1,613			801			1,372			23		18
Amortization of prior service cost	79			79			(662		)	(1,036		)	—		—
Net periodic benefit cost	$	1,314		$	871		$	202		$	961		$	256	$	281

	Nine Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	195		$	314		$	—	$	—
Interest cost	24,606			25,555			4,035			5,738			699		790
Long-term return on plan assets	(27,807		)	(28,016		)	(4,041		)	(4,179		)	—		—
Amortization of net loss	6,906			4,838			2,403			4,116			69		53
Amortization of prior service cost	237			238			(1,986		)	(3,107		)	—		—
Net periodic benefit cost	$	3,942		$	2,615		$	606		$	2,882		$	768	$	843

Texas-New Mexico Power Company [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

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

	Three Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	77		$	72		$	—	$	—
Interest cost	951			1,032			163			178			12		13
Long-term return on plan assets	(1,368		)	(1,449		)	(133		)	(129		)	—		—
Amortization of net (gain) loss	86			—			(48		)	(49		)	—		(1		)
Amortization of prior service cost	—			—			15			15			—		—
Net Periodic Benefit Cost (Income)	$	(331	)	$	(417	)	$	74		$	87		$	12	$	12

	Nine Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	231		$	217		$	—	$	—
Interest cost	2,853			3,095			489			533			36		39
Long-term return on plan assets	(4,104		)	(4,346		)	(399		)	(386		)	—		—
Amortization of net (gain) loss	258			—			(144		)	(147		)	—		(3		)
Amortization of prior service cost	—			—			45			45			—		—
Net Periodic Benefit Cost (Income)	$	(993	)	$	(1,251	)	$	222		$	262		$	36	$	36

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Earnings Per Share

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

In accordance with GAAP, dual presentation of basic and diluted earnings per share has been 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,
	2011		2010		2011		2010
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	43,662	$	48,552	$	64,366	$	62,981
Average Number of Common Shares:
Outstanding during period	86,673		86,673		86,673		86,673
Equivalents from convertible preferred stock (Note 7)	4,363		4,778		4,638		4,778
Vested awards of restricted stock	164		111		154		105
Average Shares - Basic	91,200		91,562		91,465		91,556
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	542		219		516		258
Average Shares - Diluted	91,742		91,781		91,981		91,814
Net Earnings Per Share of Common Stock:
Basic	$	0.48	$	0.53	$	0.70	$	0.69
Diluted	$	0.48	$	0.53	$	0.70	$	0.69

(1) Excludes the effect of out-of-the-money options for 1,923,608 shares of common stock at September 30, 2011.

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Capitalization, Convertible Preferred Stock (Details) (USD $)	0 Months Ended	9 Months Ended		9 Months Ended		9 Months Ended
	Oct. 05, 2011 Repurchase of Equity [Member]	Sep. 30, 2011 Preferred Stock [Member]	Sep. 23, 2011 Cascade [Member] Series A Convertible Preferred Stock [Member]	Sep. 30, 2011 Series A Convertible Preferred Stock [Member]	Sep. 23, 2011 Series A Convertible Preferred Stock [Member]	Sep. 30, 2011 Common Stock [Member]	Sep. 23, 2011 Common Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding			477,800
Convertible Preferred Stock, Shares Issued upon Conversion							4,778,000
Convertible Preferred Stock, Dicount on Price					2.00%
Payments for Repurchase of Convertible Preferred Stock	$ 73,500,000
Stock Repurchased During Period, Value		$ 100,000,000				$ (5,288,000)
Convertible Preferred Stock, Settlement Terms				Common shares
Preferred Stock, Liquidation Preference Per Share (dollars per share)				$ 0.10

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Condensed Consolidated Statements of Changes in Equity (USD $) In Thousands	Total	Public Service Company of New Mexico [Member]	Texas-New Mexico Power Company [Member]	Preferred Stock, Series A [Member]	Common Stock [Member]	Common Stock [Member] Public Service Company of New Mexico [Member]	Common Stock [Member] Texas-New Mexico Power Company [Member]	Additional Paid-in Capital [Member] Texas-New Mexico Power Company [Member]	AOCI [Member]	AOCI [Member] Public Service Company of New Mexico [Member]	AOCI [Member] Texas-New Mexico Power Company [Member]	Retained Earnings [Member]	Retained Earnings [Member] Public Service Company of New Mexico [Member]	Retained Earnings [Member] Texas-New Mexico Power Company [Member]	Total PNMR Common Stockholders' Equity [Member]	Total PNMR Common Stockholders' Equity [Member] Public Service Company of New Mexico [Member]	Non-controlling Interest in Valencia [Member]	Non-controlling Interest in Valencia [Member] Public Service Company of New Mexico [Member]	Common Stock [Member]	Common Stock [Member] Preferred Stock, Series A [Member]	Common Stock [Member]	Common Stock [Member] AOCI [Member]	Common Stock [Member] Retained Earnings [Member]	Common Stock [Member] Total PNMR Common Stockholders' Equity [Member]	Common Stock [Member] Non-controlling Interest in Valencia [Member]	Preferred Stock [Member]	Preferred Stock [Member] Preferred Stock, Series A [Member]	Preferred Stock [Member] Common Stock [Member]	Preferred Stock [Member] AOCI [Member]	Preferred Stock [Member] Retained Earnings [Member]	Preferred Stock [Member] Total PNMR Common Stockholders' Equity [Member]	Preferred Stock [Member] Non-controlling Interest in Valencia [Member]
Balance at Dec. 31, 2010	$ 1,721,919	$ 1,208,526		$ 100,000	$ 1,290,465	$ 1,018,776			$ (68,666)	$ (66,786)		$ 314,943	$ 171,359		$ 1,536,742	$ 1,123,349	$ 85,177	$ 85,177
Balance TNMP at Dec. 31, 2010	1,536,742	1,123,349	453,283				64	430,108			(1,485)			24,596
Proceeds from stock option exercise	2,570			0	2,570				0			0			2,570		0
Purchases to satisfy awards of common stock																			(5,288)	0	(5,288)	0	0	(5,288)	0	(73,510)	(100,000)	26,490	0	0	26,490	0
Stock based compensation expense	4,302			0	4,302				0			0			4,302		0
Valencia's transactions with its owner	(11,972)	(11,972)		0	0	0			0	0		0	0		0	0	(11,972)	(11,972)
Net earnings before subsidiary preferred stock dividends	75,526	51,634	17,134	0	0	0	0	0	0	0	0	64,762	40,870	17,134	64,762	40,870	10,764	10,764
Subsidiary preferred stock dividends	(396)			0	0				0			(396)			(396)		0
Total other comprehensive income (loss)	(4,247)	(5,180)	906	0	0	0	0	0	(4,247)	(5,180)	906	0	0	0	(4,247)	(5,180)	0	0
Dividends declared on preferred stock		(396)				0				0			(396)			(396)		0
Dividends declared on common stock	(33,695)	(8,212)	(7,066)	0	0	0	0	(7,066)	0	0	0	(33,695)	(8,212)	0	(33,695)	(8,212)	0	0
Balance TNMP at Sep. 30, 2011	1,591,240	1,150,431	464,257				64	423,042			(579)			41,730
Balance at Sep. 30, 2011	1,675,209	1,234,400		0	1,318,539	1,018,776			(72,913)	(71,966)		345,614	203,621		1,591,240	1,150,431	83,969	83,969
Balance at Jun. 30, 2011
Net earnings before subsidiary preferred stock dividends	47,905	42,572	8,868
Subsidiary preferred stock dividends	(132)
Total other comprehensive income (loss)	(2,222)	(3,498)	1,339
Balance TNMP at Sep. 30, 2011	1,591,240	1,150,431	464,257
Balance at Sep. 30, 2011	$ 1,675,209	$ 1,234,400

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Significant Accounting Policies and Responsibility for Financial Statements

9 Months Ended

Sep. 30, 2011

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, 2011 and December 31, 2010, and the consolidated results of operations and comprehensive income for the three months and nine months ended September 30, 2011 and 2010, and cash flows for the nine months ended September 30, 2011 and 2010. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated.

The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. The term “Company” is used when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are indicated as such. Certain amounts in the 2010 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2011 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited, and 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 2010 Annual Reports on Form 10-K. 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.

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. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. PNMR entered into an agreement to sell First Choice on September 23, 2011 and the sale was completed on November 1, 2011. See Note 16. In addition, PNM consolidates the PVNGS Capital Trust and Valencia. PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are allocated to the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include transmission and distribution services; lease, interest, and income tax sharing payments; and dividends paid on common stock. Intercompany transactions and balances have been eliminated, as appropriate. 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 $0.125 per share in July 2011 and July 2010, 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 $0.125 per share in September 2011 and September 2010, which are reflected as being in the third quarter within "Dividends Declared per Common Share."

PNM declared cash dividends on its common stock to PNMR of $39.1 million in December 2010 that was paid in January 2011, $4.6 million in March 2011 that was paid in April 2011, and $3.6 million in June 2011 that was paid in July 2011. PNM declared and paid cash dividends to PNMR of $28.0 million in the nine months ended September 30, 2010. TNMP declared and paid cash dividends to PNMR of $7.1 million and $5.8 million in the nine months ended September 30, 2011 and 2010. TNMP dividends were recorded as reductions of its paid-in-capital.

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Fair Value of Derivative and Other Financial Instruments, Margin, Notional Amounts, Credit Rating (Details) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 300,000	$ 3,400,000
Margin Deposit Assets	28,900,000	32,000,000
Derivative, Collateral, Obligation to Return Cash	0	0
Contractual Liability	12,787,000	8,113,000
Existing Cash Collateral	0	0
Net Exposure	4,026,000	2,642,000
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Economic hedges [Member] | Derivative Long Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	1,425,000	1,882,500
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Economic hedges [Member] | Derivative Short Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	961,192	990,120
Commodity Contract [Member] | Economic hedges [Member] | Derivative Long Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	3,597,170	1,693,431
Public Service Company of New Mexico [Member]
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Cash	0	3,000,000
Margin Deposit Assets	100,000	2,100,000
Derivative, Collateral, Obligation to Return Cash	0	0
Contractual Liability	3,486,000	291,000
Existing Cash Collateral	0	0
Net Exposure	$ 3,064,000	$ 119,000

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Capitalization (Tables)

9 Months Ended

Sep. 30, 2011

Debt Disclosure [Abstract]

Schedule of Short-term Debt [Table Text Block]

Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2011		2010
	(In thousands)
PNM – Revolving credit facility	$	257,000	$	190,000
TNMP – Revolving credit facility	—		—
PNMR
Revolving credit facility	32,000		32,000
Local lines of credit	—		—
	$	289,000	$	222,000

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Jointly-Owned Electric Generating Plants (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Four Corners [Member] Beginning 2016 [Member]	Sep. 30, 2011 Jointly Owned Nuclear Power Plant [Member]
Jointly Owned Utility Plant Interests [Line Items]
Operating Lease, Original Term			40 years
Operating Lease, Extended Term			20 years
Increase (Decrease) in Asset Retirement Obligations	$ 4.2
Jointly Owned Utility, Lease Payment		$ 0.9

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Sale of FCP (Details) (USD $)			1 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Nov. 01, 2011 Sale of First Choice [Member] First Choice [Member]	Sep. 30, 2011 First Choice [Member]	Sep. 23, 2011 First Choice [Member]	Dec. 31, 2010 First Choice [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontiuned Operations, Agreed Upon Sale Price					$ 270,000,000
Proceeds from Divestiture of Businesses			329,300,000
Current assets of business unit held for sale
Cash and cash equivalents				3,462,000		3,888,000
Accounts receivable, net of allowance for uncollectible accounts of $11,009 and $9,694				49,749,000		25,719,000
Allowance for uncollectibe accounts				11,009,000		9,694,000
Unbilled revenues				38,527,000		26,666,000
Derivative instruments				28,452,000		14,556,000
Other current assets				45,929,000		44,408,000
Current assets of business unit held for sale	166,119,000	0		166,119,000		115,237,000
Non-current assets of business unit held for sale
Net property and equipment				7,345,000		6,986,000
Goodwill and other intangible assets				69,308,000		69,439,000
Derivative instruments				8,817,000		5,264,000
Other long-term assets				15,589,000		10,718,000
Non-current assets of business unit held for sale	101,059,000	0		101,059,000		92,407,000
Current liabilities of business unit held for sale
Accounts payable				40,757,000		28,157,000
Affiliate accounts payable				6,632,000		5,001,000
Derivative instruments				39,272,000		28,297,000
Other current liabilities				17,254,000		17,085,000
Current liabilities of business unit held for sale	103,915,000	0		103,915,000		78,540,000
Non-current liabilities of business unit held for sale
Derivative instruments				14,460,000		10,823,000
Other long-term liabilities				3,136,000		4,847,000
Non-current liabilities of business unit held for sale	$ 17,596,000	$ 0		$ 17,596,000		$ 15,670,000

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Capitalization, Financing Activities (Details) (USD $)	9 Months Ended							9 Months Ended		0 Months Ended					0 Months Ended					9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Oct. 24, 2011 PNM Resources [Member] Maximum [Member] Repayment of Debt [Member] Unsecured Debt [Member] Senior Unsecured Notes Due 2021 [Member]	Oct. 24, 2011 PNM Resources [Member] Maximum [Member] Repayment of Debt [Member] Unsecured Debt [Member] Senior Unsecured Notes, Series A, Due 2015 [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Series 2011 Abonds [Member] Secured Debt [Member] Term Loan Agreement 2011 [Member] Commercial Mortgage Backed Securities [Member]	Oct. 06, 2011 Public Service Company of New Mexico [Member] Issuance of Debt [Member] Unsecured Debt [Member] Senior Unsecured Notes Due 2021 [Member]	Oct. 24, 2011 PNM Resources [Member] Repayment of Debt [Member] Unsecured Debt [Member] Senior Unsecured Notes, Series A, Due 2015 [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member]	Sep. 30, 2010 Texas-New Mexico Power Company [Member]	Mar. 31, 2009 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2009 [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2009 [Member] Year One to Year Three [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2009 [Member] After Three Years [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2009 [Member] January 2010 to March 2012 [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2009 [Member] After March 2012 [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2011 [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2011 [Member] Year One to Year Two And Half [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2011 [Member] After Two And A Half Years [Member]	Dec. 31, 2010 Texas-New Mexico Power Company [Member] Current Liabilities [Member]	Dec. 31, 2010 Texas-New Mexico Power Company [Member] Deferred Credits and Accumulated Other Comprehensive Income [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member]	Sep. 30, 2010 Public Service Company of New Mexico [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt	$ 50,000,000	$ 403,845,000						$ 50,000,000	$ 0	$ 50,000,000					$ 50,000,000					$ 0	$ 403,845,000
Security Owned and Pledged as Collateral, Fair Value					50,000,000
Debt Instrument, Interest Rate, Stated Percentage						5.35%	9.25%				6.05%	6.30%	4.80%	5.05%	3.566%	1.475%	1.985%
Debt Instrument, Priced As Percent of Face Amount						99.857%
Cash Flow Hedge Derivative Instrument Liabilities at Fair Value																		1,900,000	800,000
Cash Flow Hedge Derivative Instrument Assets at Fair Value															0
Debt Instrument, Pricing of Public Offering						160,000,000
Cash Tender Offer to Purchase Outstanding Debt				$ 50,000,000
Premium On Cash Tender Offer to Purchase Outstanding Debt			17.00%

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Variable Interest Entities

9 Months Ended

Sep. 30, 2011

Variable Interest Entities

Variable Interest Entities [Text Block]

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.

On April 18, 2007, PNM entered into a PPA to purchase all of the electric capacity and energy from Valencia, a natural gas-fired power plant near Belen, New Mexico. Valencia became operational on May 30, 2008. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. The total construction cost for the facility was $90.0 million. The term of the PPA is for 20 years beginning June 1, 2008, with the full output of the plant estimated to be 145 MW. During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or of the entity that owns the plant. PNM estimates that the plant will typically operate during peak periods of energy demand in summer. PNM is obligated to pay fixed O&M and capacity charges in addition to variable O&M charges under this PPA. For the three months and nine months ended September 30, 2011, PNM paid $4.6 million and $13.7 million for fixed charges and $0.9 million and $1.3 million for variable charges. For the three months and nine months ended September 30, 2010, PNM paid $4.6 million and $13.5 million for fixed charges and $0.8 million and $1.0 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 evaluated the accounting treatment of this arrangement and 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 since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. The significant factors considered in reaching that conclusion are that PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. As the primary beneficiary, PNM has consolidated the entity in its financial statements beginning on the commercial operations date. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the consolidated financial statements of PNM although PNM has no legal ownership interest or voting control of the variable interest entity. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
				(In thousands)
Operating revenues	$	5,505		$	5,275		$	15,024		$	14,502
Operating expenses	(1,394		)	(1,366		)	(4,260		)	(4,197		)
Earnings attributable to non-controlling interest	$	4,111		$	3,909		$	10,764		$	10,305

Financial Position

	September 30,		December 31,
	2011		2010
	(In thousands)
Current assets	$	3,588	$	2,372
Net property, plant and equipment	81,493		83,617
Total assets	85,081		85,989
Current liabilities	1,112		812
Owners’ equity – non-controlling interest	$	83,969	$	85,177

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. There are currently eight separate lease agreements with eight different trusts whose beneficial owners are five different institutional investors. PNM is not the legal or tax owner of the leased assets. The beneficial owners of the trusts possess all of the voting control and pecuniary interests in the trusts. 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. PNM has options to renew the leases at fixed rates set forth in the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities. 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 $105.1 million as of September 30, 2011 over the remaining 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, 2011, PNM could have been required to pay the beneficial owners up to approximately $178.3 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 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, 2011 and $26.0 million at December 31, 2010 and 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 2010 Annual Reports on Form 10-K.

PNM has evaluated the PVNGS lease arrangements 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. The significant factors considered in reaching this conclusion are: the periods covered by fixed price renewal options are significantly shorter than the anticipated remaining useful lives of the assets, particularly since on April 21, 2011 the NRC approved an extension in the operating licenses for the plants for 20 years through 2045 for Unit 1 and 2046 for Unit 2 (see Note 13); PNM’s only financial obligation to the trusts is to make the fixed lease payments and the payments do not vary based on the output of the plants or their performance; during the lease term, the economic performance of the trusts is substantially fixed due to the fixed lease payments; PNM is only one of several participants in PVNGS and is not the operating agent for the plants, so PNM does not significantly influence the day to day operations of the plants; furthermore, the operations of the plants, including plans for their decommissioning, are highly regulated by the NRC, leaving little room for the participants to operate the plants in a manner that impacts the economic performance of the trusts; the economic performance of the trusts at the end of the lease terms is dependent upon the fair value and remaining lives of the plants at that time, which are determined by factors such as power prices, outlook for nuclear power, and the impacts of potential carbon legislation or regulation, all which are outside of PNM’s control; and while PNM has some potential benefit from its renewal options, the vast majority of the value at the end of the leases will accrue to the beneficial owners of the trusts, particularly given increases in the value of existing nuclear generating facilities, which emit no GHG, resulting from anticipated carbon legislation or regulation.

PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. This arrangement was entered into prior to December 31, 2003 and PNM has been 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 is unable to make those determinations and, as provided in GAAP, continues to account for this PPA as an operating lease. PNM makes fixed and variable payments to Delta under the PPA. 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. For the three months and nine months ended September 30, 2011, PNM incurred fixed payments of $1.5 million and $4.5 million and variable payments of $0.7 million and $1.0 million under the PPA. For the three months and nine months ended September 30, 2010, PNM incurred fixed payments of $1.5 million and $4.5 million and variable payments of $0.2 million and $0.4 million under the PPA. PNM’s only quantifiable obligation under the PPA is to make the fixed payments, which as of September 30, 2011, aggregated $52.6 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. PNM has no other obligations or commitments with respect to Delta.

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Fair Value of Derivative and Other Financial Instruments, Avaialbe for Sale Securities (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	$ 157,001		$ 157,001		$ 156,922
Available-for-sale securities, Unrealized gains	18,255		18,255		26,835
Available-for-sale securities, Unrealized losses	0		0
Proceeds from sales	26,312	20,813	121,202	57,098
Gross realized gains	2,800	1,568	16,290	4,999
Gross realized (losses)	(1,847)	(1,227)	(4,129)	(3,099)
Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	22,051		22,051		25,491
Available-for-sale securities, Unrealized gains	1,137		1,137		5,108
Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	47,358		47,358		48,237
Available-for-sale securities, Unrealized gains	12,356		12,356		17,239
Multinational [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	12,509		12,509		10,670
Available-for-sale securities, Unrealized gains	243		243		2,730
Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	39,316		39,316		37,595
Available-for-sale securities, Unrealized gains	2,486		2,486		837
U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	22,779		22,779		21,541
Available-for-sale securities, Unrealized gains	1,305		1,305		348
Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	9,292		9,292		8,402
Available-for-sale securities, Unrealized gains	728		728		573
Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	3,696		3,696		4,986
Available-for-sale securities, Unrealized gains	0		0		0
Public Service Company of New Mexico [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized losses	$ 0		$ 0

XML

Fair Value of Derivative and Other Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value of Derivative and Other Financial Instruments [Abstract]

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

Commodity derivative instruments are summarized as follows:

	PNMR						PNM
	Economic Hedges						Economic Hedges
	September 30, 2011			December 31, 2010			September 30, 2011			December 31, 2010
	(In thousands)
Current assets	$	32,168		$	15,999		$	3,716		$	1,443
Deferred charges	9,064			5,264			247			—
	41,232			21,263			3,963			1,443
Current liabilities	(41,018		)	(31,407		)	(1,746		)	(3,110		)
Long-term liabilities	(16,373		)	(12,831		)	(1,913		)	(2,009		)
	(57,391		)	(44,238		)	(3,659		)	(5,119		)
Net	$	(16,159	)	$	(22,975	)	$	304		$	(3,676	)

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

The following table presents the effect of commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.

	Economic Hedges						Trading Transactions					Qualified Cash Flow Hedges
	September 30,						September 30,					September 30,
	2011			2010			2011		2010			2011			2010
Three Months Ended	(In thousands)
PNMR
Electric operating revenues	$	2,915		$	(2,131	)	$	—	$	30		$	—		$	9,006
Cost of energy	(2,873		)	(20,222		)	—		—			66			(684		)
Total gain (loss)	$	42		$	(22,353	)	$	—	$	30		$	66		$	8,322
Recognized in OCI												$	(66	)	$	(6,531	)
PNM
Electric operating revenues	$	2,915		$	(2,131	)	$	—	$	—		$	—		$	9,006
Cost of energy	(562		)	(1,781		)	—		—			—			(35		)
Total gain (loss)	$	2,353		$	(3,912	)	$	—	$	—		$	—		$	8,971
Recognized in OCI												$	—		$	(7,181	)
Nine Months Ended
PNMR
Electric operating revenues	$	4,250		$	(4,138	)	$	—	$	(3	)	$	—		$	22,294
Cost of energy	(2,788		)	(49,451		)	—		—			(183		)	(1,930		)
Total gain (loss)	$	1,462		$	(53,589	)	$	—	$	(3	)	$	(183	)	$	20,364
Recognized in OCI												$	183		$	(11,349	)
PNM
Electric operating revenues	$	4,250		$	(4,138	)	$	—	$	—		$	—		$	22,294
Cost of energy	(404		)	(5,443		)	—		—			—			(21		)
Total gain (loss)	$	3,846		$	(9,581	)	$	—	$	—		$	—		$	22,273
Recognized in OCI												$	—		$	(13,259	)

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

The table below presents PNMR’s and PNM’s net buy (sell) volume positions:

	Economic Hedges
	Decatherms	MWh
September 30, 2011
PNMR	27,187,500	3,597,170
PNM	1,425,000	(961,192	)
December 31, 2010
PNMR	22,767,500	1,693,431
PNM	1,882,500	(990,120	)

Schedule of Collateral Related to Derivative [Table Text Block]

Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
September 30, 2011
PNMR	$	12,787	$	—	$	4,026
PNM	$	3,486	$	—	$	3,064
December 31, 2010
PNMR	$	8,113	$	—	$	2,642
PNM	$	291	$	—	$	119

Available-for-sale Securities [Table Text Block]

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

	September 30, 2011				December 31, 2010
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Equity securities:
Domestic value	$	1,137	$	22,051	$	5,108	$	25,491
Domestic growth	12,356		47,358		17,239		48,237
Multinational	243		12,509		2,730		10,670
Fixed income securities:
Municipals	2,486		39,316		837		37,595
U.S. Government	1,305		22,779		348		21,541
Corporate and other	728		9,292		573		8,402
Cash and equivalents	—		3,696		—		4,986
	$	18,255	$	157,001	$	26,835	$	156,922

Realized gains and losses are determined by specific identification of costs of securities sold.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
				(In thousands)
Proceeds from sales	$	26,312		$	20,813		$	121,202		$	57,098
Gross realized gains	$	2,800		$	1,568		$	16,290		$	4,999
Gross realized (losses)	$	(1,847	)	$	(1,227	)	$	(4,129	)	$	(3,099	)

Investments Classified by Contractual Maturity Date [Table Text Block]

At September 30, 2011, 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	$	683	$	—	$	—
After 1 year through 5 years	20,259		123,206		112,083
After 5 years through 10 years	10,740		3,370		—
Over 10 years	39,705		—		—
	$	71,387	$	126,576	$	112,083

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

The carrying amount and fair value of held-to-maturity debt securities and other non-derivative financial instruments (including current maturities) are:

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
PNMR
Long-term debt	$	1,566,329	$	1,751,691	$	1,565,847	$	1,659,674
Investment in PVNGS lessor notes	$	107,435	$	108,345	$	136,145	$	141,663
Other investments	$	14,639	$	21,070	$	18,791	$	21,675
PNM
Long-term debt	$	1,055,760	$	1,107,490	$	1,055,748	$	1,056,864
Investment in PVNGS lessor notes	$	107,435	$	108,345	$	136,145	$	141,663
Other investments	$	4,193	$	4,522	$	5,068	$	5,563
TNMP
Long-term debt	$	310,807	$	423,253	$	310,337	$	385,220
Other investments	$	267	$	267	$	282	$	282

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

The fair values of derivatives and investments that are recorded at fair value on the Condensed Consolidated Balance Sheets are as follows:

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
September 30, 2011				(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	3,696		$	3,696		$	—		$	—
Equity securities:
Domestic value	22,051			22,051			—			—
Domestic growth	47,358			47,358			—			—
Multinational	12,509			12,509			—			—
Fixed income securities:
U.S. government	22,779			18,149			4,630			—
Municipals	39,316			—			39,316			—
Corporate and other	9,292			—			9,292			—
Total NDT investments	$	157,001		$	103,763		$	53,238		$	—
PNMR
Commodity derivative assets	$	41,232		$	19,589		$	18,982		$	1,302
Commodity derivative liabilities	(57,391		)	(41,574		)	(14,094		)	(364		)
Net	$	(16,159	)	$	(21,985	)	$	4,888		$	938
PNM
Commodity derivative assets	$	3,963		$	—		$	3,963		$	—
Commodity derivative liabilities	(3,659		)	—			(3,659		)	—
Net	$	304		$	—		$	304		$	—

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
December 31, 2010	(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	4,986		$	4,986		$	—		$	—
Equity securities:
Domestic value	25,491			25,491			—			—
Domestic growth	48,237			48,237			—			—
Multinational	10,670			10,670			—			—
Fixed income securities:
U.S. government	21,541			16,613			4,928			—
Municipals	37,595			—			37,595			—
Corporate and other	8,402			—			8,402			—
Total NDT investments	$	156,922		$	105,997		$	50,925		$	—
PNMR
Commodity derivative assets	$	21,263		$	8,646		$	12,308		$	272
Commodity derivative liabilities	(44,238		)	(26,378		)	(16,729		)	(1,094		)
Net	$	(22,975	)	$	(17,732	)	$	(4,421	)	$	(822	)
PNM
Commodity derivative assets	$	1,443		$	—		$	1,443		$	—
Commodity derivative liabilities	(5,119		)	—			(5,119		)	—
Net	$	(3,676	)	$	—		$	(3,676	)	$	—

(1) The Level 1, 2 and 3 columns in the above table are presented based on the nature of each instrument. The total column is presented based on the balance sheet classification of the instruments and reflect unit of account reclassifications between commodity derivative assets and commodity derivative liabilities of $1.4 million for PNMR and zero for PNM at September 30, 2011 and less than $0.1 million for PNMR and zero for PNM at December 31, 2010. There were no transfers between levels for the three months and nine months ended September 30, 2011 and 2010.

Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

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

	PNMR						PNM
	September 30,						September 30,
	2011			2010			2011		2010
Three Months Ended	(In thousands)
Balance at beginning of period	$	4,392		$	(278	)	$	—	$	—
Total gains (losses) included in earnings	(5,025		)	(945		)	—		—
Purchases	429			34			—		—
Settlements	1,142			(83		)	—		—
Balance at end of period	$	938		$	(1,272	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	589		$	(994	)	$	—	$	—
Nine Months Ended
Balance at beginning of period	$	(822	)	$	248		$	—	$	(17	)
Total gains (losses) included in earnings	201			(1,759		)	—		(128		)
Purchases	3,163			34			—		—
Settlements	(1,604		)	205			—		145
Balance at end of period	$	938		$	(1,272	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	1,455		$	(1,537	)	$	—	$	—

Fair Value, Gains Losses From Level 3 Inputs Effect on Statement of Financial Performance [Table Text Block]

Gains and losses (realized and unrealized) for Level 3 fair value measurements included in earnings are reported in operating revenues and cost of energy as follows:

	PNMR						PNM
	September 30,						September 30,
	2011			2010			2011		2010
Three Months Ended	(In thousands)
Gains (losses) included in earnings:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	(5,025		)	(945		)	—		—
Total	$	(5,025	)	$	(945	)	$	—	$	—
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	589			(994		)	—		—
Total	$	589		$	(994	)	$	—	$	—
Nine Months Ended
Gains (losses) included in earnings:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	201			(1,759		)	—		(128		)
Total	$	201		$	(1,759	)	$	—	$	(128	)
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—		$	—		$	—	$	—
Cost of energy	1,455			(1,537		)	—		—
Total	$	1,455		$	(1,537	)	$	—	$	—

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2011

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

See Note 11 for information concerning Optim Energy. 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,
	2011		2010		2011		2010
	(In thousands)
Electricity, transmission and distribution related services billings:
TNMP to PNMR	$	12,196	$	11,495	$	30,608	$	30,717
Services billings:
PNMR to PNM	24,680		26,373		70,849		69,948
PNMR to TNMP	7,295		6,798		21,250		19,090
PNM to TNMP	40		100		327		379
TNMP to PNMR	48		53		145		266
PNMR to Optim Energy	1,277		1,393		4,083		4,304
Optim Energy to PNMR	4		107		23		157
Income tax sharing payments:
PNMR to PNM	—		—		—		35,190
Interest charges:
TNMP to PNMR	8		57		36		242
PNM to PNMR	9		—		45		—
PNMR to PNM	33		—		97		—

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Fair Value of Derivative and Other Financial Instruments, Sale of Power (Details) (Public Service Company of New Mexico [Member], USD $) In Millions, unless otherwise specified	9 Months Ended	32 Months Ended
	Sep. 30, 2011 mw	Dec. 31, 2010 mw
Sale of Power [Line Items]
Long Term Contract for Sale of Electric Power Plant Output	135	135
Firm Contract [Member]
Sale of Power [Line Items]
Long Term Contract for Sale of Electric Power Plant Output		90
Firm Contract 1 [Member]
Sale of Power [Line Items]
Prepayments		40.6
Firm Contract 2 [Member]
Sale of Power [Line Items]
Prepayments		30.0
Contingent Contract [Member]
Sale of Power [Line Items]
Long Term Contract for Sale of Electric Power Plant Output		45

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2011

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

Schedule of Option Activity Including Exerciseable and Future Grant Information [Table Text Block]

The following table summarizes activity in stock option plans for the nine months ended September 30, 2011:

	Shares		Weighted- Average Exercise Price		Aggregate Intrinsic Value			Weighted- Average Remaining Contract Life
Outstanding at beginning of period	3,948,262		$	18.33
Granted	—		$	—
Exercised	(254,394	)	$	10.99
Forfeited	(10,333	)	$	11.26
Expired	(102,338	)	$	24.96
Outstanding at end of period	3,581,197		$	18.68	$	8,950,188	(1)	5.12 years
Exercisable at end of period	3,045,556		$	21.97	$	6,011,541		4.60 years
Options available for future grant(2)	4,820,656

(1) At September 30, 2011, the exercise price of 1,923,608 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

(2) Includes shares available for grants of restricted stock.

Schedule of Additional Stock Option Activity [Table Text Block]

The following table provides additional information concerning stock option activity:

	Nine Months Ended September 30,
Options for PNMR Common Stock	2011		2010
Weighted-average grant date fair value of options granted	$	—	$	3.05
Total fair value of options that vested (in thousands)	$	1,189	$	1,027
Total intrinsic value of options exercised (in thousands)	$	1,077	$	474

Schedule of Nonvested Share Activity [Table Text Block]

The following table summarizes nonvested restricted stock activity for the nine months ended September 30, 2011:

Nonvested Restricted Stock	Shares		Weighted- Average Grant-Date Fair Value
Nonvested at beginning of period	237,021		$	9.24
Granted	308,985		$	13.10
Vested	(113,576	)	$	9.54
Forfeited	(1,000	)	$	13.67
Nonvested at end of period	431,430		$	11.92

Schedule of Nonvested Share Activity Additional Information [Table Text Block]

The following table provides additional information concerning restricted stock:

	Nine Months Ended
	September 30,
Nonvested Restricted Stock	2011			2010
Weighted-average grant date fair value of shares granted	$	13.10		$	9.37
Total fair value of shares that vested (in thousands)	$	1,084		$	1,365
Expected quarterly dividends per share	$	0.125		$	0.125
Risk-free interest rate	1.20		%	1.36		%

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Regulatory and Rate Matters

9 Months Ended

Sep. 30, 2011

Regulatory and Rate Matters

Regulatory and Rate Matters

Regulatory and Rate Matters

Information concerning regulatory and rate matters is contained in Note 17 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

PNMR

First Choice Request for ERCOT Alternative Dispute Resolution

In June 2008, First Choice filed a request for alternative dispute resolution with ERCOT alleging that ERCOT incorrectly applied its protocols with respect to congestion management during the first quarter of 2008. First Choice requested that ERCOT resolve the dispute by restating certain elements of its first quarter 2008 congestion management data and by refunding to First Choice allegedly overstated congestion management charges. The amount at issue in First Choice's claim can only be determined by running ERCOT market models with corrected inputs but First Choice believes that the amount is significant. ERCOT protocols provide that ERCOT will notify potentially impacted market participants and subsequently consider the merits of First Choice's allegations. In September 2011, ERCOT forwarded information on its actions which is under review. PNMR is unable to predict the outcome of this matter. However, this matter was terminated prior to closing of the sale of First Choice (see Note 16).

PNM

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 stipulation in the 2010 Electric Rate Case discussed below as approved by the NMPRC, the parties to the stipulation, including the NMPRC staff, will jointly request that the NMPRC take no further action in this matter and close the docket. PNM anticipates this filing will be made in the fourth quarter of 2011. PNM is unable to predict the outcome of this matter.

Renewable Portfolio Standard

The REA was enacted to encourage the development of renewable energy in New Mexico. The act establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 5% of retail electric sales by January 1, 2006, increasing to 10% by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified” beginning in 2011 when no less than 20% of the renewable portfolio requirement must be met by wind energy, no less than 20% by solar energy, no less than 10% by other renewable technologies, and no less than 1.5% by distributed generation. The act provides for streamlined proceedings for approval of utilities' renewable energy procurement plans, assures utilities recovery of costs incurred consistent with approved procurement plans and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. The NMPRC has established a RCT for 2011 of 2% of all customers' aggregated overall annual electric charges that increases by 0.25% annually until reaching 3% in 2015.

In August 2010, the NMPRC partially approved PNM's revised 2010 procurement plan, including PNM's investment in 22 MW of solar PV facilities at various PNM sites and the construction of a solar-storage demonstration project. The NMPRC capped recoverable costs at a maximum of $107.7 million. Under the REA, costs incurred pursuant to and consistent with an approved procurement plan are deemed to be reasonable and recoverable in the ratemaking process. Construction of these facilities is underway, the first 17 MW of solar PV and the solar-storage demonstration project were in service at October 31, 2011, and PNM anticipates that the remaining 5 MW of solar PV will be in service by December 31, 2011. PNM anticipates requesting recovery of these costs from customers through a rate rider. See 2010 Electric Rate Case below.

On July 1, 2010, PNM filed its renewable energy procurement plan for 2011. The 2011 plan proposed the procurement of 250,000 MWh of RECs from another New Mexico public utility for compliance with the renewable portfolio standard in 2011. On October 5, 2010, the NMPRC issued an order rejecting PNM's plan for 2011 as incomplete because certain planning assumptions used in the plan were found to be outdated, and ordered PNM to file a new plan within 60 days. On December 6, 2010, PNM filed a revised 2011 plan that proposed procurement of 423,860 MWh of wind generated RECs, but not the associated energy, from various bidders selected through a RFP process at a total cost of up to $5.5 million. The RECs would be retired for RPS compliance for 2011. The plan, as amended, requested a variance from the diversity requirements for solar and certain “other resources” for 2011 based on the RCT and availability constraints. A public hearing on the plan was held in April 2011. On June 2, 2011, the NMPRC issued an order that rejected PNM's proposal to procure wind RECs and directed PNM to use its best efforts to procure wind energy and associated RECs for 2011 compliance. The NMPRC granted PNM a variance from the resource diversity requirement conditioned upon PNM including in its 2012 procurement plan a proposal that would meet the diversity requirements by April 5, 2013. On July 1, 2011, PNM filed a motion for rehearing based on the NMPRC's disapproval of the use of RECs to meet the RPS requirements, the requirement that PNM meet the diversity requirements without explicit recognition of potential RCT constraints, the failure of the final order to adopt language concerning the relationship of the billing system modifications to the third party provider amendments to the Public Utility Act, and other matters. The NMPRC staff and NMIEC also filed motions for rehearing on the issue of the use of RECs for RPS compliance. On September 1, 2011, the NMPRC affirmed its order concerning cost recovery of the billing system modifications and its disapproval of the proposed REC purchase, and confirmed that the resource diversity requirements were subject to the reasonable cost threshold. On September 14, 2011, PNM filed a motion for expedited clarification of the order or in the alternative for approval of the procurement of additional wind resources. On October 3, 2011, NMIEC filed an appeal of the NMPRC's orders in the New Mexico Supreme Court. On October 11, 2011, the NMPRC denied PNM's request for clarification of the order and directed PNM to proceed with the procurement described in its request through the remainder of 2011 unless the NMPRC staff filed in opposition by October 20, 2011. On October 14, 2011, PNM filed a motion for stay of the NMPRC's orders, which the NMPRC denied on October 20, 2011. A stay motion by NMIEC is still pending. On October 17, 2011, the NMPRC staff filed an objection to the procurement and requested that the NMPRC issue an order finding that the procurement was not in the public interest. On October 27, 2011, the NMPRC issued an order rejecting the NMPRC staff's objection and directing PNM to procure the wind energy identified in its September 14, 2011 request. On October 28, 2011, PNM filed a motion in the New Mexico Supreme Court to become a party to the appeal previously filed by NMIEC. PNM cannot predict the outcome of this matter.

On July 1, 2011, PNM filed its Renewable Energy Portfolio Procurement Plan for 2012. The plan requests a variance from the RPS due to RCT limitations and also requests a variance from the RCT to allow PNM to continue to procure RECs from retail customers under PNM's Solar REC Incentive Program and to procure a small number of RECs from a hydroelectric resource to be developed by the City of Santa Fe. The plan is diversity compliant based on the reduced RPS, except for non-wind/non-solar resources, which are not currently available. In addition to the proposed procurements and requested variances, the plan describes two other portfolios: one that would be fully compliant with the RPS and a second that would comply with both the full RPS and the diversity requirements for wind, solar, and distributed generation. Each of these portfolios is more costly than PNM's proposed portfolio and the plan did not request approval of them since they would exceed the RCT. Several intervenors and the NMPRC staff filed testimony in opposition to the manner in which PNM calculated the effect of the RCT and to other portions of the plan. A hearing was held in October 2011. PNM cannot predict the outcome of this matter.

NMPRC Rulemaking on Disincentives/Incentives to Energy Efficiency Programs

The NMPRC approved amendments to its energy efficiency rule on April 8, 2010 to be effective May 3, 2010. The amended rule allowed utilities to collect rate adders of $0.01 per KWh for lifetime energy savings and $10 per kilowatt for demand savings related to energy efficiency (collectively, the "interim adder") and demand response programs beginning in 2010. The amended rule also required investor-owned electric utilities to make filings by July 1, 2010 that proposed rate design and ratemaking measures to remove regulatory disincentives or barriers to achieve energy efficiency savings. PNM included its proposals in the 2010 Electric Rate Case described below. In the approved stipulation in the 2010 Electric Rate Case, PNM agreed that any such disincentives would be deemed addressed under the new rates allowed under the stipulation. Under the amended rule, after such measures became effective, the rate adder for energy saving was reduced to $0.005 per KWh (collectively, the "reduced adder"). The NMAG and NMIEC appealed the NMPRC order adopting the amended rule to the New Mexico Supreme Court, which issued an opinion on July 27, 2011 that annulled and vacated the NMPRC's order adopting the amended rule and remanded the matter to the NMPRC. PNM cannot predict the ultimate outcome of this matter.

On May 5, 2010, PNM filed proposed tariffs under the amended rule to recover a disincentive/incentive adder related to 2010 efficiency programs. PNM proposed to recover $6.2 million over a twelve-month period following NMPRC approval. The staff of the NMPRC filed testimony recommending the recovery of not more than $4.2 million. Following a hearing, the NMPRC issued an order authorizing recovery of $4.2 million over 12 months. PNM implemented a rate rider to recover the $4.2 million adder on December 29, 2010. The final order on the PNM 2010 Energy Efficiency Application described below extended the recovery period from 12 months to 18 months. As a result of the Supreme Court decision issued on July 27, 2011 PNM filed revised tariffs and ceased collecting this adder on August 21, 2011. Of the $4.2 million authorized for recovery, approximately $2.6 million had been collected through August 20, 2011. A NMPRC order on August 16, 2011 initiated an investigation to determine whether PNM should be required to refund any adder revenues that had been collected under the amended rule. The Hearing Examiner in the case arising from the reconciliation of 2010 program costs (see 2010 Energy Efficiency Application below) recommended that PNM not be required to refund any of the $2.6 million of 2010 adder revenue that had been collected as of August 21, 2011. The NMPRC issued an order on November 1, 2011 that generally approved the Hearing Examiner's recommended decision that PNM not be required to refund any of the interim adder revenue collected as of August 20, 2011, but left open the possibility that it may order a refund of interim adder revenue related to any disallowed program costs. On November 3, 2011, the NMPRC issued an order that allows for continuation of collection of reduced adder revenues. PNM cannot predict the outcome of this matter.

2010 Energy Efficiency Application

On September 15, 2010, PNM filed an energy efficiency program application for programs to be offered beginning July 1, 2011. PNM requested revisions to existing programs, revisions of estimates of participation and expenditure levels, approval of revised program cost recovery tariff riders, and approval of disincentive/incentive adders for 2011 energy efficiency and demand response programs. The total amount that PNM proposed to recover through the tariff riders was $32.9 million, which included the 2010 disincentive/incentive adder discussed above. Based on testimony filed by other parties, PNM accepted certain modifications to the plan, which resulted in a revised proposed recovery amount of $31.4 million. Following a hearing, the NMPRC issued a final order on June 23, 2011 that rejected the proposed plan modifications and ordered modifications to some programs in the original plan. The final order also adopted a recommendation by the NMPRC staff that the incentive adder rates of $0.005 per kWh and $10 per KW proposed by PNM be reduced to $0.002 per kWh and $4 per kW. The final order deferred consideration of certain issues relating to the recovery of past program costs, including whether PNM's demand response programs comply with statutory requirements, to a separate proceeding on PNM's 2010 Annual Electric Energy Efficiency Report. The final order approved a rider recovery amount of $22.8 million, including $17.1 million in program costs, $3.8 million for 2011 disincentive/incentive adders, and $1.9 million for 2010 disincentive/inventive adders that were not collected as of July 27, 2011, the effective date for the new rider rate approved by the NMPRC. The new rider rate of 3.018% was effective with bills rendered July 27, 2011. PNM filed a new rider effective August 21, 2011 that incorporated the higher rates approved in the 2010 Electric Rate case and eliminated recovery of the remaining 2010 disincentive/incentive adder revenues of $1.6 million and the 2011 disincentive adder revenue of $2.5 million consistent with the Supreme Court decision in the appeal of the disincentive rulemaking discussed above. The new rider rate is 2.262%.

On April 1, 2011, PNM filed a reconciliation of energy efficiency program costs and collections as of December 31, 2010. Included in this filing was an adjustment of the adder amount to reflect the measured and verified savings for 2010 program participation in its 2010 Annual Electric Energy Efficiency Report, also filed April 1, 2011. PNM proposed an adjustment to the energy efficiency rider to recover an under-collected balance of $2.6 million. The new energy efficiency rider rate, adjusted for the under collected program costs and adjusted savings, would be increased from 2.441% to 2.839%. After suspending the proposed adjusted rates the NMPRC concluded that some of the program costs exceeded approved budgets and determined that an evidentiary hearing should be held to consider whether PNM should be permitted to recover over-budget program costs and certain adder amounts and whether sanctions should be imposed on PNM. In June 2011, PNM and the NMPRC staff reached an agreement on issues raised by the reconciliation filing and the suspension order under which PNM would be permitted recovery of substantially all of its program costs and would not be subject to any sanctions. PNM and the NMPRC staff filed testimony supporting the agreement. No party filed testimony in opposition. In a hearing held in July 2011, the Hearing Examiner questioned the reconciliation of 2009 Energy Efficiency Plan costs and identified costs of approximately $1.4 million, which may have exceeded NMPRC-approved budgets by more than 25% and for which NMPRC approval should have been obtained. The Hearing Examiner issued a recommended decision on October 3, 2011 that PNM should make permanent its suspension of the 2010 disincentive/incentive adder and that recovery of under-collected past program costs should be reduced to $2.4 million to account for the $0.3 million by which PNM's spending for its residential load management program exceeded 125% of the approved budget for program year 2009. PNM and another party filed exceptions to the recommended decision disallowing the $0.3 million and to other recommendations on October 13, 2011. The NMPRC issued a final order on November 1, 2011 that approved recovery of substantially all of the under-collected program costs through December 31, 2010, provided that PNM makes a compliance filing demonstrating the cost-effectiveness of one of the programs.

Investigation on Establishing a Policy Linking Utility Earnings to Quality of Customer Service

On May 28, 2009, the NMPRC ordered an investigation to consider the development of a service quality incentive mechanism for utilities in New Mexico, including PNM. The parties were to look at quality of service mechanisms established in other NMPRC orders, as well as the mechanisms that have been implemented in other states. Following a workshop process, the Hearing Examiner filed a report concluding that present circumstances do not warrant the implementation of a performance based ratemaking mechanism to either reward or penalize utilities for quality of service. Instead, the report recommended that utilities be required to file certain customer service reports annually for a three-year period commencing in 2011. The NMPRC issued an order on March 24, 2011 requiring utilities to file annually reports as recommended in the Hearing Examiner's report. These reports are to be filed annually by June 30 of 2011, 2012, and 2013. PNM made its first annual compliance filing on June 24, 2011.

Rates for Former TNMP Customers in New Mexico

PNM serves the former New Mexico customers of TNMP (“TNMP-NM” or “PNM South”) under rates approved by the NMPRC in its order approving PNMR's acquisition of TNMP. Under that order, rates charged to TNMP-NM customers were set through December 31, 2010. In January 2009, the NMPRC directed PNM to estimate the revenue requirement increase that would be reflected in a TNMP-NM rate application for rates effective January 2011. PNM estimated that the rate increase could be between 40% and 56% depending on fuel costs. In April 2009, the NMPRC directed PNM, the NMPRC staff, and other parties to attempt to reach consensus on ways to mitigate the impact of this potential rate increase and appointed a mediator. Mediation did not result in an agreement. On May 25, 2010, the NMPRC issued an order directing PNM and the NMPRC staff to file testimony addressing certain matters related to cost allocation. A hearing was held in December 2010. In April 2011, the NMPRC issued an order that consolidated this case with the pending 2010 Electric Rate Case discussed below. The NMPRC's order in the 2010 Electric Rate Case discussed below allows PNM to serve former TNMP customers in New Mexico under the same tariffs, including the FPPAC, that are applicable to all of PNM's other retail customers in New Mexico.

2010 Electric Rate Case

PNM filed its 2010 Electric Rate Case application with the NMPRC on June 1, 2010 for rate increases for all PNM retail customers to be effective April 1, 2011. The application proposed separate rate increases for those customers served by PNM (“PNM North”) prior to its acquisition of TNMP and for the customers formerly served by TNMP (“PNM South”). The proposed total increase of $165.2 million represented a 22% increase for PNM North and a 20% increase for PNM South. The filed revenue requirements were based on a future test period ending December 31, 2011. PNM proposed to implement the increase in two phases. Phase 1 would have become effective April 1, 2011 (PNM North: $111.1 million, 16%; PNM South: $8.7 million, 14%), and Phase 2 would have become effective January 1, 2012 (PNM North: $41.7 million, 6%; PNM South: $3.6 million, 6%). PNM also proposed to implement a FPPAC for PNM South. This was the first rate case filing in New Mexico proposing a future test year consistent with recent amendments to the Public Utility Act. The NMPRC initially suspended the rates until April 1, 2011, which date was later extended.

In October 2010, PNM began meeting with the NMPRC staff and other parties to discuss settlement. On February 3, 2011, PNM, NMPRC staff, NMAG, NMIEC, ABCWUA, Buckman Direct Diversion Board, and the City of Alamogordo, New Mexico entered into a stipulation that, if approved by the NMPRC, would have resolved all issues in the 2010 Electric Rate Case and provided a rate path for PNM through December 31, 2013. Other parties filed statements opposing the stipulation. This stipulation, which reflected some aspects of a future test year, was subject to approval of the NMPRC. The stipulation would have allowed PNM to increase rates by $45.0 million immediately following approval and by an additional $40.0 million beginning January 1, 2012. The proposed rates were designed so that PNM North customers and PNM South customers would have the same percentage increase. The PNM South customers would also be covered by the same FPPAC that is utilized for the PNM North customers. In addition, subject to further NMPRC approvals, PNM would be able to recover the costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning July 1, 2012 or twelve months after the effective date of the new electric rates and would also be able to implement a separate rate rider in 2013 to recover up to an additional $20.0 million to cover changes in plant-related rate base between June 30, 2010 and December 31, 2012. PNM's next general rate adjustment could not go into effect before January 1, 2014, except that PNM could file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010. In addition, the stipulation would limit the amount that could be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs during the period covered by the stipulation. Recovery of costs in excess of the limits would be deferred for collection, without carrying costs, to future periods. If the stipulation was approved, PNM would forego collection of $10.0 million of the under-collected amount in the FPPAC balancing account as a regulatory disallowance. On March 17, 2011, PNM filed a request for interim rates to go into effect on May 15, 2011, which was denied by the NMPRC. A public hearing on the stipulation was held in May 2011. The hearing examiner issued a Certification of the Stipulation on June 21, 2011. The Hearing Examiner recommended approval of most of the terms of the stipulation, including the $85.0 million rate increase, the implementation of the increase in two phases, the moratorium on rate changes through December 31, 2013 the application of PNM North rate schedules to all New Mexico customers, and approval of a consolidated fuel clause. The Hearing Examiner, however, recommended disapproval of the capital additions rider and the proposed residential rate design. PNM and other parties filed exceptions to the Certification of the Stipulation. On August 8, 2011, the NMPRC issued a final order that provides for a $72.1 million rate increase, rejects the capital additions rider, changes the residential rate design, and adopts, approves, and accepts the stipulation with other modifications. PNM and other parties to the stipulation filed an amended stipulation on August 11, 2011 that conforms to the modifications contained in the NMPRC's August 8, 2011 order. No party requested rehearing of the order. The amended stipulation allows PNM to file a new rate case for rates to be effective July 1, 2013. PNM implemented the new rates on August 21, 2011.

As a result of the above, PNM recorded a pre-tax loss for the $10.0 million of fuel costs discussed above that will not be recovered through the FPPAC. In addition, PNM recorded a pre-tax loss aggregating $7.5 million for costs that will not be recovered in rates approved by the NMPRC order. These costs primarily relate to rate case expenses for the 2010 Electric Rate Case, expenses related to an audit of fuel and purchased power costs, loss on debt re-acquired in previous years, and the 2010 settlement of claims against DOE related to spent nuclear fuel at PVNGS. These amounts were recorded as of June 30, 2011 and are reflected as regulatory disallowances on PNM's Condensed Consolidated Statement of Earnings.

2011 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 must contain an action plan covering the first four years of that period. In its most recent IRP, which was filed on July 18, 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. However, PNM has not entered into any commitments regarding these plans beyond what is otherwise described herein. 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 in the event that at least two parties request mediation. PNM is unable to predict the outcome of this matter.

Transmission Rate Case

On October 27, 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually and revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms.  If approved, the rate increase would apply to all of PNM's wholesale electric transmission service customers, which include other utilities, electric co-operatives, and entities that use PNM's transmission system to transmit power at the wholesale level.  The proposed rate increase would not impact PNM's retail customers. On December 29, 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. PNM and other parties to the case have engaged in settlement discussions and will continue the negotiation process under the settlement judge procedures, but due to an impasse in regards to settlement negotiations, the settlement judge issued an order in August 2011 designating an ALJ, establishing procedural time standards, and terminating settlement judge procedures. The hearing for this proceeding is scheduled to commence on April 4, 2012. PNM is unable to predict the outcome of this proceeding.

Firm Requirements Rate Case

On September 15, 2011, PNM filed an amended sales agreement between PNM and Navopache Electric Cooperative, Inc. (“NEC”) with FERC. The agreement proposes a cost of service based rate for the partial requirements electric service and ancillary services PNM provides to NEC, which would result in an annual increase of $8.7 million (39.8%) over rates PNM currently charges NEC. PNM also proposes a FPPAC and full recovery of certain third-party transmission charges PNM incurs to serve NEC. The proposed effective date is November 14, 2011. NEC has filed a protest to PNM's filing with FERC. PNM is unable to predict the outcome of this proceeding.

TNMP

TNMP Competitive Transition Charge True-Up Proceeding

The purpose of the true-up proceeding was to quantify and reconcile the amount of stranded costs that TNMP may recover, as a CTC, from its transmission and distribution customers. A 2004 PUCT decision established $87.3 million as TNMP's stranded costs. TNMP and other parties made a series of appeals on the ruling. On June 24, 2011, the Texas Supreme Court denied all petitions for review pending in the case. The decision rejects the argument that TNMP's stranded cost balance should be zero. It also denied TNMP's request to remand the case in order to present further evidence of stranded costs that the PUCT previously refused to consider. TNMP filed a motion for rehearing on July 11, 2011 requesting the Texas Supreme Court to reconsider its decision on TNMP's request to present additional stranded costs. No other party filed a motion for rehearing. The Texas Supreme Court denied the motion for rehearing on August 12, 2011 concluding this matter.

Interest Rate Compliance Tariff

Following a revision of the interest rate on TNMP's CTC, TNMP filed a compliance tariff to implement the new 8.31% rate. TNMP's filing proposed to put the new rates into effect on February 1, 2008. Intervenors asserted objections to the compliance filing. PUCT staff urged that the PUCT make the new rate effective as of December 27, 2007 when the PUCT's order establishing the correct rate became final. After regulatory proceedings, the PUCT issued an order making the new rate retroactive to July 20, 2006. TNMP filed an appeal of this order in the District Court in Austin, Texas. A hearing was held on June 17, 2010. On June 28, 2010, the District Court reversed the PUCT decision and remanded the matter back to the PUCT for a determination that is not retroactive. The PUCT and other parties appealed the decision to the Texas 3^rd Court of Appeals and presented oral argument on March 23, 2011. On May 12, 2011, the 3^rd Court of Appeals issued its opinion reversing the District Court and reaffirming the PUCT's decision. TNMP filed its petition for review with the Texas Supreme Court on July 29, 2011. Responses from opposing parties are to be filed by November 9, 2011. TNMP is unable to predict if the Texas Supreme Court will review the decision or the ultimate outcome of this matter. However, due to the new retroactive ratemaking theory contained in the Texas 3^rd Court of Appeals opinion, TNMP recorded a regulatory disallowance of $3.9 million, before income taxes, in the three months ended June 30, 2011 to reflect the impact of applying the 8.31% rate retroactively.

Advanced Meter System Deployment and Surcharge Request

On May 26, 2010, TNMP filed a request with the PUCT to approve TNMP's proposed advanced meter deployment. The filing also requested a surcharge to collect $157.9 million in costs over 12 years, including recovery of capital expenditures of $70.6 million. Due to changes in the tax law, TNMP filed supplemental testimony on February 16, 2011 to reflect the effects of the bonus depreciation, a new WACC, and other changes. The filing amended the requested surcharge to collect $126.1 million, including capital expenditures of $70.2 million incurred through 2015. On May 18, 2011, the parties announced a settlement that permits TNMP to collect the costs of a $113.3 million advanced meter deployment. The settlement approves a lower cost deployment due principally to the removal of an outage management system from TNMP's proposal. The settlement was approved by the PUCT on July 8, 2011. TNMP began collecting the surcharge on August 11, 2011 in order to collect a total of $113.3 million in costs over 12 years. Deployment of advanced meters began in September 2011.

2010 Rate Case

On August 26, 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues, requesting that new rates go into effect on October 1, 2010. In its request, TNMP also asked for permission to update its catastrophe reserve fund that would be utilized to pay for a utility system's costs in recovering from natural disasters and acts of terrorism. Additionally, TNMP requested a rate rider to recover costs to storm harden its system. On November 8, 2010, the presiding ALJ severed the rate case expense issues into a separate proceeding. In December 2010, the parties announced to the ALJ that a settlement had been reached in the case and a stipulation supporting the settlement was filed. The settlement provided for a revenue requirement increase of $10.25 million, a return on equity of 10.125%, and a hypothetical 55%/45% debt-equity capital structure. The PUCT approved the settlement on January 27, 2011. TNMP implemented the new rates on February 1, 2011.

2010 Rate Case Expense Proceeding

The determination of the amount of reasonable rate case expenses incurred by TNMP and other parties in TNMP's 2010 Rate Case was severed into a separate proceeding. On January 26, 2011, the ALJ set a procedural schedule requiring the parties who participated in the 2010 rate case to file testimony supporting their respective incurred expenses. The parties agreed to a settlement of the case, which was approved by the PUCT on May 26, 2011. TNMP began collecting $2.8 million over three years on July 1, 2011.

Remand of ERCOT Transmission Rates for 1999 and 2000

Following a variety of appeals, the ERCOT transmission rates approved in 1999 and 2000 were recently remanded back to the PUCT.  The issues relevant to TNMP are addressed in three separate dockets, but those proceedings are expected to be heard jointly.  These dockets concern the recalculation of rates for the fourth quarter of 1999 and all of 2000 to correct over-payments made by certain market participants and the recovery of additional, undetermined transmission costs by City Public Service Board of San Antonio ("CPS"). On October 5, 2011, TNMP joined in a non-unanimous settlement of the issues relating to resettlement of the last four months of 1999. CPS is the sole opposing party. The settlement would resolve all issues except CPS's claim that it can file a transmission rate case in 2011 to determine its actual rates for the fourth quarter of 1999 and all of 2000. As that claim is pending in a separate docket, the settlement does not prejudice CPS' right to pursue the claim in the pending proceeding. TNMP would receive $1.6 million under the settlement, if approved. However, whether such funds would have to be passed on to customers would be determined in TNMP's next transmission cost recovery factor filing. TNMP cannot predict the ultimate outcome of this matter.

Energy Efficiency

On April 29, 2011, TNMP filed an application for approval of its 2012 energy efficiency programs and requested recovery through an energy efficiency cost recovery factor. TNMP estimates the costs of its 2012 energy efficiency programs to be $4.4 million and requests to collect this amount based on a per customer charge over 12 months. Additionally, as permitted by the PUCT rules, TNMP's request includes a bonus collection amount of $0.3 million due to the fact that its 2010 energy efficiency programs exceeded the performance goals set by the PUCT. On June 23, 2011, the PUCT issued a supplemental preliminary order clarifying that certain costs totaling $0.4 million that, due to a PUCT rule change, TNMP expects to incur during its current 2011 program should be considered in its energy efficiency 2012 filing and not in the current proceeding. On August 2, 2011, TNMP and the other parties announced a settlement of the material issues in this matter. The settlement allows TNMP to collect the $0.3 million bonus for 2010 and estimated 2012 program costs of $3.4 million and sets, for good cause, TNMP's 2012 demand savings goal at 4.8 MW instead of the 5.9 MW goal that would otherwise apply. The settlement does not alter the current PUCT energy efficiency rules permitting recovery of any under-collection that might exist after the 2012 program year. TNMP received a final order on September 13, 2011 that approved the settlement in whole, except a minor amount for under-recovery of administrative costs from the 2010 energy efficiency expenses. TNMP's new rates will be effective January 1, 2012.

Periodic Rate Adjustment

On May 28, 2011, the Governor of Texas signed Senate Bill 1693, which will allow for an annual periodic rate adjustment to reflect changes in investments in distribution assets. To implement the new statute, the PUCT opened a rule-making proceeding. A proposed rule was published by the PUCT in the Texas Register on July 22, 2011. Comments to the new rule were filed in August 2011. A public hearing was held on August 15, 2011. The PUCT approved a new rule on September 27, 2011. The rule allows ERCOT distribution utilities to only file for a periodic rate adjustment during the period April 1 through April 8 of each year and requires the PUCT to deny an electric utility's application for a periodic rate adjustment if the electric utility is earning more than its authorized rate of return using weather-normalized data.

XML

Optim Energy (Details) (USD $)	3 Months Ended		9 Months Ended			1 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Dec. 31, 2010 Optim Energy [Member]	Sep. 30, 2010 Optim Energy [Member]	Sep. 30, 2011 Optim Energy [Member]	Sep. 30, 2010 Optim Energy [Member]	Sep. 23, 2011 Optim Energy [Member]	Sep. 22, 2011 Optim Energy [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage										1.00%	50.00%
Commitments and Contingencies
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
Net earnings (loss)							7,600,000		(6,800,000)
PNMR equity in net earnings (loss) of Optim Energy	0	2,495,000	0	(5,714,000)			2,500,000	0	(5,700,000)
Equity Method Investment Summarized Financial Information, Equity [Abstract]
PNMR equity investment in Optim Energy						0
Equity Method Investment, Other than Temporary Impairment						$ 188,200,000

XML

Segment Information

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

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 Electric

PNM Electric includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM Electric provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico, generation services to firm requirements customers in New Mexico and Arizona, and the sale of transmission to third parties. PNM Electric also includes the generation and sale of electricity into the wholesale market. This includes the asset optimization of PNM’s jurisdictional assets as well as the capacity of PVNGS Unit 3, which is excluded from retail rates. FERC has jurisdiction over wholesale power and transmission rates.

TNMP Electric

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

First Choice

First Choice is a certified retail electric provider operating in Texas, which allows it to provide electricity to residential, small commercial, and governmental customers. Although First Choice is regulated in certain respects by the PUCT, it is not subject to traditional rate regulation. PNMR entered into an agreement to sell First Choice on September 23, 2011 and the sale was completed on November 1, 2011. See Note 16.

Optim Energy

PNMR owned 50% of Optim Energy until September 23, 2011, when PNMR's ownership interest was reduced to 1%. Optim Energy was considered a separate segment for PNMR, which was held in the Corporate and Other segment. PNMR accounted for its investment in Optim Energy using the equity method of accounting until September 23, 2011 and is using the cost method thereafter. Optim Energy’s revenues and expenses are not included in PNMR’s consolidated revenues and expenses or the following tables. PNMR fully impaired its investment in Optim Energy as of December 31, 2010. See Note 11.

Corporate and Other

PNMR Services Company is included in the Corporate and Other segment.

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

PNMR SEGMENT INFORMATION

	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended September 30, 2011	(In thousands)
Operating revenues	$	323,760		$	54,787		$	170,999		$	(48	)	$	549,498
Intersegment revenues	—			12,196			—			(12,196		)	—
Total revenues	323,760			66,983			170,999			(12,244		)	549,498
Cost of energy	108,708			10,307			144,035			(12,196		)	250,854
Gross margin	215,052			56,676			26,964			(48		)	298,644
Other operating expenses	102,080			22,451			25,076			(1,617		)	147,990
Depreciation and amortization	25,058			12,674			346			4,292			42,370
Operating income (loss)	87,914			21,551			1,542			(2,723		)	108,284
Interest income	3,770			1			29			(52		)	3,748
Other income (deductions)	(5,573		)	313			(115		)	(1,664		)	(7,039		)
Net interest charges	(18,487		)	(7,276		)	(249		)	(5,112		)	(31,124		)
Segment earnings (loss) before income taxes	67,624			14,589			1,207			(9,551		)	73,869
Income taxes (benefit)	25,052			5,721			594			(5,403		)	25,964
Segment earnings (loss)	42,572			8,868			613			(4,148		)	47,905
Valencia non-controlling interest	(4,111		)	—			—			—			(4,111		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	38,329		$	8,868		$	613		$	(4,148	)	$	43,662
Nine Months Ended September 30, 2011
Operating revenues	$	797,232		$	150,175		$	405,485		$	(145	)	$	1,352,747
Intersegment revenues	—			30,608			—			(30,608		)	—
Total revenues	797,232			180,783			405,485			(30,753		)	1,352,747
Cost of energy	279,419			30,719			303,285			(30,609		)	582,814
Gross margin	517,813			150,064			102,200			(144		)	769,933
Other operating expenses	329,502			67,431			67,693			(7,172		)	457,454
Depreciation and amortization	71,691			33,662			987			12,775			119,115
Operating income (loss)	116,620			48,971			33,520			(5,747		)	193,364
Interest income	12,052			1			63			(106		)	12,010
Other income (deductions)	4,129			887			(494		)	(4,913		)	(391		)
Net interest charges	(54,593		)	(21,880		)	(535		)	(15,243		)	(92,251		)
Segment earnings (loss) before income taxes	78,208			27,979			32,554			(26,009		)	112,732
Income taxes (benefit)	26,574			10,845			11,833			(12,046		)	37,206
Segment earnings (loss)	51,634			17,134			20,721			(13,963		)	75,526
Valencia non-controlling interest	(10,764		)	—			—			—			(10,764		)
Subsidiary preferred stock dividends	(396		)	—			—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	40,474		$	17,134		$	20,721		$	(13,963	)	$	64,366
At September 30, 2011:
Total Assets	$	3,936,468		$	1,041,613		$	274,741		$	119,818		$	5,372,640
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310
Additions to utility and non-utility plant included in accounts payable	$	6,811		$	4,672		$	106		$	253		$	11,842

	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended September 30, 2010	(In thousands)
Operating revenues	$	304,268		$	49,709		$	149,729		$	(53	)	$	503,653
Intersegment revenues	—			11,495			—			(11,495		)	—
Total revenues	304,268			61,204			149,729			(11,548		)	503,653
Cost of energy	98,030			9,276			119,358			(11,495		)	215,169
Gross margin	206,238			51,928			30,371			(53		)	288,484
Other operating expenses	102,452			20,711			23,952			(3,019		)	144,096
Depreciation and amortization	23,111			11,594			210			4,065			38,980
Operating income (loss)	80,675			19,623			6,209			(1,099		)	105,408
Interest income	4,523			—			3			(27		)	4,499
Equity in net earnings (loss) of Optim Energy	—			—			—			2,495			2,495
Other income (deductions)	1,902			88			(66		)	(1,603		)	321
Net interest charges	(18,011		)	(7,661		)	(364		)	(5,281		)	(31,317		)
Segment earnings (loss) before income taxes	69,089			12,050			5,782			(5,515		)	81,406
Income taxes (benefit)	25,926			4,721			2,225			(4,059		)	28,813
Segment earnings (loss)	43,163			7,329			3,557			(1,456		)	52,593
Valencia non-controlling interest	(3,909		)	—			—			—			(3,909		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	39,122		$	7,329		$	3,557		$	(1,456	)	$	48,552
Nine Months Ended September 30, 2010
Operating revenues	$	777,864		$	131,233		$	384,034		$	(266	)	$	1,292,865
Intersegment revenues	—			30,717			—			(30,717		)	—
Total revenues	777,864			161,950			384,034			(30,983		)	1,292,865
Cost of energy	264,102			27,383			296,469			(30,716		)	557,238
Gross margin	513,762			134,567			87,565			(267		)	735,627
Other operating expenses	318,353			58,534			65,652			(10,109		)	432,430
Depreciation and amortization	68,887			31,728			683			12,336			113,634
Operating income (loss)	126,522			44,305			21,230			(2,494		)	189,563
Interest income	14,538			1			16			53			14,608
Equity in net earnings (loss) of Optim Energy	—			—			—			(5,714		)	(5,714		)
Other income (deductions)	11,069			717			(164		)	(4,544		)	7,078
Net interest charges	(54,473		)	(23,483		)	(1,062		)	(15,470		)	(94,488		)
Segment earnings (loss) before income taxes	97,656			21,540			20,020			(28,169		)	111,047
Income taxes (benefit)	34,748			8,461			7,363			(13,207		)	37,365
Segment earnings (loss)	62,908			13,079			12,657			(14,962		)	73,682
Valencia non-controlling interest	(10,305		)	—			—			—			(10,305		)
Subsidiary preferred stock dividends	(396		)	—			—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	52,207		$	13,079		$	12,657		$	(14,962	)	$	62,981
At September 30, 2010:
Total Assets	$	3,812,829		$	1,004,785		$	259,621		$	303,574		$	5,380,809
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310

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Jointly-Owned Electric Generating Plants

9 Months Ended

Sep. 30, 2011

Regulated Operations [Abstract]

Jointly Owned Electric Generating Plants

Jointly-Owned Electric Generating Plants

Information concerning Jointly-Owned Electric Generating Plants is discussed in Note 14 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. As discussed in that note, operation of each of the three PVNGS units requires an operating license from the NRC and a portion of PNM’s interests in PVNGS Units 1 and 2 are held under leases that expire in 2015 and 2016. The NRC issued 40 year operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. In December 2008, APS, on behalf of the PVNGS participants, applied for renewed operating licenses for the PVNGS units for a period of 20 years beyond the expirations of the current licenses. On April 21, 2011, the NRC approved extensions in the operating licenses for the plants for 20 years through 2045 for Unit 1, 2046 for Unit 2, and 2047 for Unit 3.

Information concerning the Company's AROs is contained in Note 15 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. PNM has an ARO for PVNGS that includes the obligation for nuclear decommissioning of that facility. In the second quarter of 2011, PNM adopted a new decommissioning study for PVNGS that reflects updated cash flow estimates and the 20-year license extension, which extends the commencement of decommissioning to 2045. The new study resulted in a $4.2 million decrease to the ARO liability for asset retirements and electric plant in service.

The Four Corners plant site is leased from the Navajo Nation and is also subject to a rights-of-way grant from the federal government. APS, on behalf of the Four Corners participants, negotiated amendments to the facility lease with the Navajo Nation, which would extend the Four Corners leasehold interest to 2041. The amendments have been approved by the Navajo Nation Council and signed by the Nation’s President. The effectiveness of the amendments also requires the approval of the DOI, as does the related federal rights-of-way grant, which the Four Corners participants will pursue. A federal environmental review will be conducted as part of the DOI review process.PNM’s share of the annual lease payments will be $0.9 million beginning in 2016.

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Fair Value of Derivative and Other Financial Instruments, Statement of Earnings Information (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Electric operating revenues [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 2,915	$ (2,131)	$ 4,250	$ (4,138)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Electric operating revenues [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	0	0	0
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Electric operating revenues [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	9,006	0	22,294
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Cost of energy [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	(562)	(1,781)	(404)	(5,443)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Cost of energy [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	0	0	0
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Cost of energy [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	(35)	0	(21)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	2,353	(3,912)	3,846	(9,581)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	0	0	0
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	8,971	0	22,273
Recognized in OCI	0	(7,181)	0	(13,259)
Commodity Contract [Member] | Electric operating revenues [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	2,915	(2,131)	4,250	(4,138)
Commodity Contract [Member] | Electric operating revenues [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	30	0	(3)
Commodity Contract [Member] | Electric operating revenues [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	9,006	0	22,294
Commodity Contract [Member] | Cost of energy [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	(2,873)	(20,222)	(2,788)	(49,451)
Commodity Contract [Member] | Cost of energy [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	0	0	0
Commodity Contract [Member] | Cost of energy [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	66	(684)	(183)	(1,930)
Commodity Contract [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	42	(22,353)	1,462	(53,589)
Commodity Contract [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	30	0	(3)
Commodity Contract [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	66	8,322	(183)	20,364
Recognized in OCI	(66)	(6,531)	183	(11,349)
Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			100
Public Service Company of New Mexico [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			$ 0

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

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,
	2011		2010		2011		2010
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	43,662	$	48,552	$	64,366	$	62,981
Average Number of Common Shares:
Outstanding during period	86,673		86,673		86,673		86,673
Equivalents from convertible preferred stock (Note 7)	4,363		4,778		4,638		4,778
Vested awards of restricted stock	164		111		154		105
Average Shares - Basic	91,200		91,562		91,465		91,556
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	542		219		516		258
Average Shares - Diluted	91,742		91,781		91,981		91,814
Net Earnings Per Share of Common Stock:
Basic	$	0.48	$	0.53	$	0.70	$	0.69
Diluted	$	0.48	$	0.53	$	0.70	$	0.69

(1) Excludes the effect of out-of-the-money options for 1,923,608 shares of common stock at September 30, 2011.

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash Flows From Operating Activities:
Net earnings	$ 75,526	$ 73,682
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	151,984	138,013
PVNGS firm-sales contract revenue	(2,558)	(43,535)
Bad debt expense	20,120	21,023
Deferred income tax expense (benefit)	43,167	23,276
Equity in net (earnings) loss of Optim Energy	0	5,714
Net unrealized (gains) losses on derivatives	(5,869)	41,649
Realized (gains) on investments held by NDT	(7,688)	(2,606)
Stock based compensation expense	4,302	2,525
Regulatory disallowances	21,402	0
Other, net	3,549	3,820
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(88,462)	(44,710)
Materials, supplies, and fuel stock	(985)	(2,557)
Other current assets	(2,901)	(54,654)
Other assets	(3,310)	(4,781)
Accounts payable	13,781	(9,380)
Accrued interest and taxes	33,049	141,478
Other current liabilities	(12,919)	(47,201)
Other liabilities	(43,691)	(25,198)
Net cash flows from operating activities	198,497	216,558
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(236,275)	(181,340)
Proceeds from sales of investments held by NDT	121,202	57,098
Purchases of investments held by NDT	(122,174)	(59,395)
Return of principal on PVNGS lessor notes	32,274	29,851
Investments in Optim Energy	0	(17,610)
Other, net	145	636
Net cash flows from investing activities	(204,828)	(170,760)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	67,000	(6,000)
Long-term borrowings	50,000	403,845
Repayment of long-term debt	(50,000)	(403,845)
Proceeds from stock option exercise	2,570	1,117
Purchases to satisfy awards of common stock	(5,288)	(2,804)
Excess tax (shortfall) from stock-based payment arrangements	0	(264)
Dividends paid	(34,690)	(34,691)
Equity transactions with Valencia's owner	(11,972)	(11,149)
Payments received on PVNGS firm-sales contracts	2,558	22,872
Proceeds from transmission interconnection agreements	1,246	0
Repayment of transmission interconnection agreements	(4,637)	0
Debt issuance costs and other	(100)	(4,423)
Net cash flows from financing activities	16,687	(35,342)
Change in Cash and Cash Equivalents	10,356	10,456
Cash and Cash Equivalents at Beginning of Period	15,404
Cash and Cash Equivalents at Beginning of Period		14,641
Cash and Cash Equivalents at End of Period	25,760	25,097
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	64,130	67,824
Income taxes paid (refunded), net	(3,744)	(98,792)
Supplemental schedule of noncash financing activities:
Liability incurred for purchase of Convertible Preferred Stock, Series A	73,475
Public Service Company of New Mexico [Member]
Cash Flows From Operating Activities:
Net earnings	51,634	62,908
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	97,918	85,289
PVNGS firm-sales contract revenue	(2,558)	(43,535)
Deferred income tax expense (benefit)	33,835	33,934
Net unrealized (gains) losses on derivatives	(4,120)	7,157
Realized (gains) on investments held by NDT	(7,688)	(2,606)
Regulatory disallowances	17,479	0
Other, net	5,786	6,529
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(25,871)	(8,938)
Materials, supplies, and fuel stock	(974)	(1,949)
Other current assets	1,626	(21,861)
Other assets	8,187	6,431
Accounts payable	(2,013)	(406)
Accrued interest and taxes	18,186	53,266
Other current liabilities	(4,173)	(51,652)
Other liabilities	(45,417)	(29,614)
Net cash flows from operating activities	141,837	94,953
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(185,402)	(150,087)
Proceeds from sales of investments held by NDT	121,202	57,098
Purchases of investments held by NDT	(122,174)	(59,395)
Return of principal on PVNGS lessor notes	32,274	29,851
Other, net	496	1,165
Net cash flows from investing activities	(153,604)	(121,368)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	67,000	55,000
Long-term borrowings	0	403,845
Repayment of long-term debt	0	(403,845)
Dividends paid	(47,730)	(28,392)
Equity transactions with Valencia's owner	(11,972)	(11,149)
Payments received on PVNGS firm-sales contracts	2,558	22,872
Proceeds from transmission interconnection agreements	1,246	0
Repayment of transmission interconnection agreements	(4,637)	0
Debt issuance costs and other	0	(4,298)
Net cash flows from financing activities	6,465	34,033
Change in Cash and Cash Equivalents	(5,302)	7,618
Cash and Cash Equivalents at Beginning of Period	10,336	1,373
Cash and Cash Equivalents at End of Period	5,034	8,991
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	40,582	43,298
Income taxes paid (refunded), net	(1,539)	(35,189)
Texas-New Mexico Power Company [Member]
Cash Flows From Operating Activities:
Net earnings	17,134	13,079
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	36,352	34,748
Deferred income tax expense (benefit)	9,981	(6,015)
Regulatory disallowances	3,923	0
Other, net	(69)	(939)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(8,751)	(3,660)
Materials, supplies, and fuel stock	124	(641)
Other current assets	(1,547)	(1,037)
Other assets	(2,985)	(3,147)
Accounts payable	1,858	(1,253)
Accrued interest and taxes	4,277	18,034
Other current liabilities	2,383	252
Other liabilities	(1,101)	(478)
Net cash flows from operating activities	61,579	48,943
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(44,214)	(23,311)
Net cash flows from investing activities	(44,214)	(23,311)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net – affiliate	(1,200)	(19,800)
Long-term borrowings	50,000	0
Repayment of long-term debt	(50,000)	0
Dividends paid	(7,066)	(5,750)
Debt issuance costs and other	(100)	(124)
Net cash flows from financing activities	(8,366)	(25,674)
Change in Cash and Cash Equivalents	8,999	(42)
Cash and Cash Equivalents at Beginning of Period	1	138
Cash and Cash Equivalents at End of Period	9,000	96
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	14,474	14,719
Income taxes paid (refunded), net	$ 3,250	$ 2,940

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New Accounting Pronouncements

9 Months Ended

Sep. 30, 2011

New Accounting Pronouncements [Abstract]

Description of New Accounting Pronouncements Not yet Adopted [Text Block]

New Accounting Pronouncements

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

Accounting Standards Update 2011-04 - Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs

The Financial Accounting Standards Board ("FASB") released amended guidance to provide a consistent definition of fair value and to ensure fair value measurement and disclosure requirements are similar between U.S. GAAP and International Financial Reporting Standards.  The update changes certain fair value measurement principles, further enhances disclosure requirements related to transfers between hierarchy levels, and increases qualitative disclosures regarding unobservable inputs used in Level 3 measurements, including the sensitivity of recurring Level 3 measurements to changes in significant unobservable inputs. In addition, the update requires disclosure of the level within the fair value hierarchy for fair value disclosures of instruments recorded on an amortized cost basis. The update is required to be applied prospectively and is effective for interim and annual reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The Company does not believe this guidance will have a material impact on the Company's financial statements and will comply with this requirement upon its effective date.

Accounting Standards Update 2011-05 - Comprehensive Income: Presentation of Comprehensive Income

The FASB released amended guidance regarding presentation of comprehensive income in financial statements. The update requires entities to report comprehensive income in either one continuous statement of comprehensive income or in two separate but consecutive statements. Under the two-statement approach, the first statement would include components of net income consistent with current guidance, and the second statement would include components of other comprehensive income. The update is effective for interim and annual reporting periods beginning after December 15, 2011, with early adoption permitted. The Company does not believe this guidance will have a material impact on the Company's financial statements and will comply with this requirement no later than its effective date.

Accounting Standards Update 2011-08 - Intangibles-Goodwill and Other: Testing Goodwill for Impairment

The FASB released amended guidance that is intended to simplify requirements to test goodwill for impairment. Under the amended guidance, an entity will have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less that its carrying amount. If an entity determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the two-step impairment test will not be necessary. However, if an entity is unable to make this conclusion, then it will be required to perform the first step of the two-step impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit, as required by current guidance. The update is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. The Company is currently evaluating the impacts of this new standard.

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Fair Value of Derivative and Other Financial Instruments, Carrying Amount and Fair Value (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Public Service Company of New Mexico [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,055,760	$ 1,055,748
Investments in PVNGS lessor notes	107,435	136,145
Other investments	4,193	5,068
Public Service Company of New Mexico [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,107,490	1,056,864
Investments in PVNGS lessor notes	108,345	141,663
Other investments	4,522	5,563
Texas-New Mexico Power Company [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	310,807	310,337
Other investments	267	282
Texas-New Mexico Power Company [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	423,253	385,220
Other investments	267	282
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,566,329	1,565,847
Investments in PVNGS lessor notes	107,435	136,145
Other investments	14,639	18,791
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,751,691	1,659,674
Investments in PVNGS lessor notes	108,345	141,663
Other investments	$ 21,070	$ 21,675

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Sale of FCP

9 Months Ended

Sep. 30, 2011

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

Sale of First Choice

PNMR has previously reported that it was evaluating strategic alternatives with respect to 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 actual amounts of certain components of working capital at closing, pursuant to a Stock Purchase Agreement dated September 23, 2011. Closing of the transaction was subject to customary conditions, including an antitrust review under the Hart-Scott-Rodino Antitrust Improvements Act, which was received on October 7, 2011. Closing occurred on November 1, 2011, with PNMR receiving $329.3 million, which includes an estimate of the components of working capital discussed above. For accounting purposes, the sale was effective as of the close of business on October 31, 2011. Such amount is subject to adjustment based on the actual amounts of the components of working capital at October 31, 2011. PNMR expects to use the net proceeds from the sale of First Choice to repurchase, depending on market conditions, certain of PNMR's outstanding debt and equity (see Note 7) and for other corporate purposes, including repayment of borrowings under the PNMR Revolving Credit Facility. PNMR Services Company will continue to provide certain services at cost to First Choice for a transitional period of up to nine months following closing.

First Choice is reflected as being "held-for-sale" in PNMR's September 30, 2011 Condensed Consolidated Balance Sheet. Because PNMR will continue to have direct cash flows resulting from transmission and distribution services provided by TNMP to First Choice, First Choice is not reflected as discontinued operations. A summary of the major assets and liabilities reflected

as "held-for-sale" in PNMR's September 30, 2011 Condensed Consolidated Balance Sheet. The amounts included in the December 31, 2010 Condensed Consolidated Balance Sheet are also presented for comparative purposes although such amounts are not presented separately on the Condensed Consolidated Balance Sheet.

	September 30,		December 31,
	2011		2010
	(In thousands)
Current assets of business unit held for sale
Cash and cash equivalents	$	3,462	$	3,888
Accounts receivable, net of allowance for uncollectible accounts of $11,009 and $9,694	49,749		25,719
Unbilled revenues	38,527		26,666
Derivative instruments	28,452		14,556
Other current assets	45,929		44,408
	$	166,119	$	115,237
Non-current assets of business unit held for sale
Net property and equipment	$	7,345	$	6,986
Goodwill and other intangible assets, net	69,308		69,439
Derivative instruments	8,817		5,264
Other long-term assets	15,589		10,718
	$	101,059	$	92,407
Current liabilities of business unit held for sale
Accounts payable	$	40,757	$	28,157
Affiliate accounts payable	6,632		5,001
Derivative instruments	39,272		28,297
Other current liabilities	17,254		17,085
	$	103,915	$	78,540
Non-current liabilities of business unit held for sale
Derivative instruments	$	14,460	$	10,823
Other long-term liabilities	3,136		4,847
	$	17,596	$	15,670

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Condensed Consolidated Statements of Comprehensive Income (Loss) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Net earnings	$ 47,905	$ 52,593	$ 75,526	$ 73,682
Unrealized Gain (Loss) on Investment Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	(1,713)	6,516	12,448	6,428
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(2,431)	(1,747)	(17,632)	(3,776)
Pension liability adjustment, net of income tax (expense) benefit	648	0	(318)	(223)
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	(219)	1,267	(781)	6,906
Reclassification adjustment for losses included in net earnings, net of income tax expense (benefit)	1,493	(8,026)	2,036	(20,396)
Total Other Comprehensive Income (Loss)	(2,222)	(1,990)	(4,247)	(11,061)
Comprehensive Income	45,683	50,603	71,279	62,621
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,111)	(3,909)	(10,764)	(10,305)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(396)	(396)
Comprehensive Income Attributable to PNMR	41,440	46,562	60,119	51,920
Public Service Company of New Mexico [Member]
Net earnings	42,572	43,163	51,634	62,908
Unrealized Gain (Loss) on Investment Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	(1,713)	6,516	12,448	6,428
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(2,431)	(1,747)	(17,632)	(3,776)
Pension liability adjustment, net of income tax (expense) benefit	646	0	(13)	(223)
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	0	1,029	0	5,252
Reclassification adjustment for losses included in net earnings, net of income tax expense (benefit)	0	(5,379)	17	(13,329)
Total Other Comprehensive Income (Loss)	(3,498)	419	(5,180)	(5,648)
Comprehensive Income	39,074	43,582	46,454	57,260
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(4,111)	(3,909)	(10,764)	(10,305)
Comprehensive Income Attributable to PNMR	34,963	39,673	35,690	46,955
Texas-New Mexico Power Company [Member]
Net earnings	8,868	7,329	17,134	13,079
Unrealized Gain (Loss) on Investment Securities:
Pension liability adjustment, net of income tax (expense) benefit	2	0	(305)	0
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	(198)	(750)	(689)	(2,357)
Reclassification adjustment for losses included in net earnings, net of income tax expense (benefit)	1,535	166	1,900	537
Total Other Comprehensive Income (Loss)	1,339	(584)	906	(1,820)
Comprehensive Income	$ 10,207	$ 6,745	$ 18,040	$ 11,259

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Pension and Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2011

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.

Information concerning pension and other postretirement plans is contained in Note 12 of Notes to Consolidated Financial Statements in the 2010 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 table presents the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	65		$	105		$	—	$	—
Interest cost	8,202			8,518			1,345			1,913			233		263
Long-term return on plan assets	(9,269		)	(9,339		)	(1,347		)	(1,393		)	—		—
Amortization of net loss	2,302			1,613			801			1,372			23		18
Amortization of prior service cost	79			79			(662		)	(1,036		)	—		—
Net periodic benefit cost	$	1,314		$	871		$	202		$	961		$	256	$	281

	Nine Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	195		$	314		$	—	$	—
Interest cost	24,606			25,555			4,035			5,738			699		790
Long-term return on plan assets	(27,807		)	(28,016		)	(4,041		)	(4,179		)	—		—
Amortization of net loss	6,906			4,838			2,403			4,116			69		53
Amortization of prior service cost	237			238			(1,986		)	(3,107		)	—		—
Net periodic benefit cost	$	3,942		$	2,615		$	606		$	2,882		$	768	$	843

PNM made contributions to its pension plan trust of $20.5 million and $34.0 million in the three months and nine months ended September 30, 2011 and $6.5 million and $13.1 million in the three months and nine months ended September 30, 2010. PNM anticipates making additional contributions of $7.5 million in 2011.  Based on current law and estimates of portfolio performance, PNM estimates making contributions to its pension plan trust that total $163.9 million for 2012- 2015. The estimated contributions were developed using estimated discount rates and expected returns on assets to calculate the pension liabilities. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate and return on assets. PNM contributed $0.7 million and $1.9 million to the trust for other postretirement benefits for the three months and nine months ended September 30, 2011 and $0.4 million and $1.6 million for the three months and nine months ended September 30, 2010. PNM expects contributions during 2011 to the trust for other postretirement benefits to total $2.6 million.  Disbursements under the executive retirement program, which are funded by the Company and considered to be contributions to the plan, were $0.4 million and $1.2 million in the three months and nine months ended September 30, 2011 and $0.4 million and $1.1 million in the three months and nine months ended September 30, 2010 and are expected to total $1.5 million during 2011.

TNMP Plans

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

	Three Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	77		$	72		$	—	$	—
Interest cost	951			1,032			163			178			12		13
Long-term return on plan assets	(1,368		)	(1,449		)	(133		)	(129		)	—		—
Amortization of net (gain) loss	86			—			(48		)	(49		)	—		(1		)
Amortization of prior service cost	—			—			15			15			—		—
Net Periodic Benefit Cost (Income)	$	(331	)	$	(417	)	$	74		$	87		$	12	$	12

	Nine Months Ended September 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	231		$	217		$	—	$	—
Interest cost	2,853			3,095			489			533			36		39
Long-term return on plan assets	(4,104		)	(4,346		)	(399		)	(386		)	—		—
Amortization of net (gain) loss	258			—			(144		)	(147		)	—		(3		)
Amortization of prior service cost	—			—			45			45			—		—
Net Periodic Benefit Cost (Income)	$	(993	)	$	(1,251	)	$	222		$	262		$	36	$	36

TNMP made contributions to its pension plan trust of $0.8 million and $1.0 million in the three months and nine months ended September 30, 2011 and $0.2 million in the three months and nine months ended September 30, 2010. TNMP anticipates making additional contributions of $0.2 million in 2011. Based on current law and estimates of portfolio performance, TNMP estimates making contributions to its pension plan trust that total $6.0 million for 2012-2015. The estimated contributions were developed using estimated discount rates and expected returns on assets to calculate the pension liabilities. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate and return on assets. TNMP contributed zero and $0.4 million to the trust for other postretirement benefits for the three months and nine months ended September 30, 2011 and zero and $0.6 million for the three months and nine months ended September 30, 2010. TNMP does not expect to make additional contributions during 2011 to the trust for other postretirement benefits. Disbursements under the executive retirement program, which are funded by the Company and considered to be contributions to the plan, were less than $0.1 million in the three months and nine months ended September 30, 2011 and 2010 and are expected to total $0.1 million during 2011.

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Regulatory and Rate Matters (Details) (USD $)					0 Months Ended									0 Months Ended		1 Months Ended						1 Months Ended			7 Months Ended											0 Months Ended	9 Months Ended											1 Months Ended			1 Months Ended		1 Months Ended			1 Months Ended			0 Months Ended			3 Months Ended															9 Months Ended		3 Months Ended				0 Months Ended
	Sep. 30, 2011 Public Service Company of New Mexico [Member] Maximum [Member] Renewable Portfolio Standard [Member]	May 03, 2010 Public Service Company of New Mexico [Member] Maximum [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] Per KWh [Member]	Jun. 23, 2011 Public Service Company of New Mexico [Member] Maximum [Member] 2010 Energy Efficiency Application [Member] Per KWh [Member] Originally Filed [Member]	Jun. 23, 2011 Public Service Company of New Mexico [Member] Maximum [Member] 2010 Energy Efficiency Application [Member] Per kilowatt [Member] Originally Filed [Member]	Apr. 15, 2011 Public Service Company of New Mexico [Member] Maximum [Member] Rates For Former TNMP Customers in New Mexico [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member] Wind Energy [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member] Solar Energy [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member] Renewable Technologies [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member] Distributed Generation [Member]	May 03, 2010 Public Service Company of New Mexico [Member] Minimum [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] Per KWh [Member]	Jun. 23, 2011 Public Service Company of New Mexico [Member] Minimum [Member] 2010 Energy Efficiency Application [Member] Per KWh [Member] Amended [Member]	Jun. 23, 2011 Public Service Company of New Mexico [Member] Minimum [Member] 2010 Energy Efficiency Application [Member] Per kilowatt [Member] Amended [Member]	Apr. 15, 2011 Public Service Company of New Mexico [Member] Minimum [Member] Rates For Former TNMP Customers in New Mexico [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Emergency FPPAC [Member]	Aug. 31, 2010 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] mw	Sep. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] mw	Sep. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2006 [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2011 [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2015 [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2020 [Member]	Jul. 31, 2010 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Wind Energy [Member] Originally Filed [Member] mwh	Dec. 31, 2010 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Wind Energy [Member] Amended [Member] mwh	Dec. 06, 2010 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Wind Energy [Member] Amended [Member]	Aug. 21, 2011 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	Aug. 28, 2011 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	Dec. 29, 2010 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 31, 2010 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	May 05, 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 kilowatt [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member]	Jul. 27, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member]	Sep. 15, 2010 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member]	Oct. 03, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Regulatory Matters Evidentiary Hearing [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Regulatory Matters Evidentiary Hearing [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Program Costs [Member]	Apr. 15, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Originally Filed [Member]	Apr. 15, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Amended [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Aug. 08, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Jun. 21, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Feb. 03, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Immediate Enaction [Member]	Feb. 03, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Enaction Beginning 2012 [Member]	Feb. 03, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Capital Expenditures [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member] Phase One [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member] Phase One [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member] Phase Two [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member] Phase Two [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member] Phase One [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member] Phase One [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member] Phase Two [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member] Phase Two [Member]	Oct. 27, 2010 Public Service Company of New Mexico [Member] Transmission Rate Case [Member]	Sep. 15, 2011 Public Service Company of New Mexico [Member] Wholesale Power Rate Case [Member]	Jun. 24, 2011 Texas-New Mexico Power Company [Member] Competitive Transition Charge True-Up Proceeding [Member]	Dec. 31, 2004 Texas-New Mexico Power Company [Member] Competitive Transition Charge True-Up Proceeding [Member] Stranded Costs [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Interest Rate Compliance Tariff [Member]	Jan. 31, 2008 Texas-New Mexico Power Company [Member] Interest Rate Compliance Tariff [Member]	May 18, 2011 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	Feb. 26, 2011 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	May 26, 2010 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	Feb. 26, 2011 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] Capital Expenditures [Member]	May 26, 2010 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] Capital Expenditures [Member]	Jan. 27, 2011 Texas-New Mexico Power Company [Member] Rate Case, 2010 [Member]	Aug. 26, 2010 Texas-New Mexico Power Company [Member] Rate Case, 2010 [Member]	May 26, 2011 Texas-New Mexico Power Company [Member] Rate Case Expense Proceeding, 2010 [Member]	Oct. 27, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Jun. 23, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Apr. 29, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Oct. 27, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member] Related to Performance Goal [Member]	Apr. 29, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member] Related to Performance Goal [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member] Originally Filed [Member] mw	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member] Amended [Member] mw	Sep. 30, 2011 Emergency FPPAC [Member]	Sep. 30, 2011 NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	Aug. 11, 2011 NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	Aug. 11, 2011 Rate Case, 2010 [Member]	Oct. 05, 2011 ERCOT Transmission Rates [Member]
Rate Matters [Line Items]
Amount of Regulatory Costs Not yet Approved															$ 8,000,000									$ 5,500,000						$ 6,200,000					$ 32,900,000									$ 165,200,000			$ 20,000,000			$ 111,100,000		$ 41,700,000			$ 8,700,000		$ 3,600,000	$ 11,100,000	$ 8,700,000						$ 126,100,000	$ 157,900,000	$ 70,200,000	$ 70,600,000		$ 20,100,000				$ 4,400,000		$ 300,000
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales																		5.00%	10.00%	15.00%	20.00%
Public Utilities, Required Percentage of Diversification							20.00%	20.00%	10.00%	1.50%
Public Utilities, Reasonable Cost Threshold	3.00%					2.00%
Public Utilities, Annual Incremental Increase in Reasonable Cost Threshold																	0.25%
Public Utilities, Procurment of Energy, Nonmonetary																22						250,000	423,860
Public Utilities, Regulatory Costs Approved																	107,700,000									2,600,000		4,200,000							31,400,000							72,100,000																						113,300,000					10,250,000		2,800,000	3,400,000			300,000
Public Utilities, Pre-Tax Loss Not to be Recovered																																																																															10,000,000	7,500,000
Litigation Settlement, Gross																																																																																			1,600,000
Public Utilities, Current Operational Usage																	17
Public Utilities, Estimated Operational Usage in Current Fiscal Year																	5
Public Utilities, Rate Adder Allowed		0.01	0.005	10							0.005	0.002	4																		10	0.02262	0.03018						0.02441	0.02839
Public Utilities, Eliminated Recovery of Adder Revenue																																																																																	2,500,000	1,600,000
Public Utilities, Regulatory Rate Recommended For Recovery																													4,200,000														85,000,000
Public Utilities, Rate Rider to be Implemented																											4,200,000					22,800,000						17,100,000
Public Utilities, Rate Rider Recovered																									2,600,000
Public Utilities, Adder Revenue to be Implemented																																3,800,000		1,900,000
Public Utilities, Rate Rider Adjustment																																								2,600,000
Public Utilities, Regulatory Costs That Have Exceeded Approved Costs																																1,400,000
Public Utilities, Percent of Regulatory Costs in Excess of Approved																																0.25
Public Utlitiles, Judgement Amount for Recovery of Under-collected Past Program Costs																																				2,400,000
Public Utilities, Spending on Residential Load Management Program in Excess of Approved Budget																																					300,000
Public Utilities, Percentage Over the Approved Budget for Residential Load Management Program																																					125.00%
Public Utilities, Regulatory Rate Increase					0.56									0.40																																		0.22	0.16		0.06		0.20	0.14		0.06			0.398
Public Utilities, Regulatory Costs Proposed, Stipulation Increase																																													45,000,000	40,000,000
Public Utilities, Collection of Regulatory Costs Forgoed of Under Collected Amount																																									10,000,000
Regulatory Assets																																																													87,300,000
Regulatory Assets, Proposed by Company																																																												0
Public Utilities, Proposed Rate																																																															0.0831
Public Utilities, Regulatory Disallowance Before Income Taxes																																																														3,900,000
Public Utilities, Return on Equity																																																																					0.10125
Public Utitlities, Debt to Equity Capital Structure, Debt																																																																					0.55
Public Utilities, Debt to Equity Capital Structure, Equity																																																																					0.45
Amount of Regulatory Costs Not Included From Original Filing																																																																									$ 400,000
Demand Savings Goal																																																																													5.9	4.8

XML

Goodwill and Other Intangible Assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2011	Mar. 31, 2010	Dec. 31, 2007 Customer Lists [Member] years
Schedule of Goodwill and Other Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life (years)			8
Goodwill, Impairment Loss	$ 0	$ 0
Impairment of Intangible Assets, Indefinite-lived (Excluding Goodwill)	$ 0	$ 0

XML

Sale of FCP (Tables)

9 Months Ended

Sep. 30, 2011

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

A summary of the major assets and liabilities reflected

as "held-for-sale" in PNMR's September 30, 2011 Condensed Consolidated Balance Sheet. The amounts included in the December 31, 2010 Condensed Consolidated Balance Sheet are also presented for comparative purposes although such amounts are not presented separately on the Condensed Consolidated Balance Sheet.

	September 30,		December 31,
	2011		2010
	(In thousands)
Current assets of business unit held for sale
Cash and cash equivalents	$	3,462	$	3,888
Accounts receivable, net of allowance for uncollectible accounts of $11,009 and $9,694	49,749		25,719
Unbilled revenues	38,527		26,666
Derivative instruments	28,452		14,556
Other current assets	45,929		44,408
	$	166,119	$	115,237
Non-current assets of business unit held for sale
Net property and equipment	$	7,345	$	6,986
Goodwill and other intangible assets, net	69,308		69,439
Derivative instruments	8,817		5,264
Other long-term assets	15,589		10,718
	$	101,059	$	92,407
Current liabilities of business unit held for sale
Accounts payable	$	40,757	$	28,157
Affiliate accounts payable	6,632		5,001
Derivative instruments	39,272		28,297
Other current liabilities	17,254		17,085
	$	103,915	$	78,540
Non-current liabilities of business unit held for sale
Derivative instruments	$	14,460	$	10,823
Other long-term liabilities	3,136		4,847
	$	17,596	$	15,670

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Related Party Transactions

9 Months Ended

Sep. 30, 2011

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

PNMR, PNM, TNMP, and, through September 23, 2011, Optim Energy are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR, its subsidiaries, and Optim Energy in accordance with shared services agreements. There was also a services agreement for Optim Energy to provide services to PNMR. Additional information concerning the Company’s related party transactions is contained in Note 20 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

See Note 11 for information concerning Optim Energy. 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,
	2011		2010		2011		2010
	(In thousands)
Electricity, transmission and distribution related services billings:
TNMP to PNMR	$	12,196	$	11,495	$	30,608	$	30,717
Services billings:
PNMR to PNM	24,680		26,373		70,849		69,948
PNMR to TNMP	7,295		6,798		21,250		19,090
PNM to TNMP	40		100		327		379
TNMP to PNMR	48		53		145		266
PNMR to Optim Energy	1,277		1,393		4,083		4,304
Optim Energy to PNMR	4		107		23		157
Income tax sharing payments:
PNMR to PNM	—		—		—		35,190
Interest charges:
TNMP to PNMR	8		57		36		242
PNM to PNMR	9		—		45		—
PNMR to PNM	33		—		97		—

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Condensed Consolidated Statements of Earnings (USD $) In Thousands, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Electric Operating Revenues
Affiliate	$ 0	$ 0	$ 0	$ 0
Electric Operating Revenues	549,498	503,653	1,352,747	1,292,865
Operating Expenses:
Cost of energy	250,854	215,169	582,814	557,238
Administrative and general	69,755	71,193	197,016	196,398
Energy production costs	39,730	42,306	135,510	148,002
Regulatory disallowances	0	0	21,402	0
Depreciation and amortization	42,370	38,980	119,115	113,634
Transmission and distribution costs	17,925	15,012	52,962	44,574
Taxes other than income taxes	20,580	15,585	50,564	43,456
Total operating expenses	441,214	398,245	1,159,383	1,103,302
Operating income	108,284	105,408	193,364	189,563
Other Income and Deductions:
Interest income	3,748	4,499	12,010	14,608
Gains (losses) on investments held by NDT	(4,109)	2,206	7,688	2,606
Other income	1,755	1,963	3,559	13,333
Equity in net earnings (loss) of Optim Energy	0	2,495	0	(5,714)
Other deductions	(4,685)	(3,848)	(11,638)	(8,861)
Net other income (deductions)	(3,291)	7,315	11,619	15,972
Interest Charges	31,124	31,317	92,251	94,488
Earnings before Income Taxes	73,869	81,406	112,732	111,047
Income Taxes	25,964	28,813	37,206	37,365
Net Earnings	47,905	52,593	75,526	73,682
(Earnings) Attributable to Valencia Non-controlling Interest	(4,111)	(3,909)	(10,764)	(10,305)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(396)	(396)
Net Earnings Attributable to Company	43,662	48,552	64,366	62,981
Net Earnings Attributable to PNMR per Common Share:
Basic	$ 0.48	$ 0.53	$ 0.70	$ 0.69
Diluted	$ 0.48	$ 0.53	$ 0.70	$ 0.69
Dividends Declared per Common Share	$ 0.125	$ 0.125	$ 0.375	$ 0.375
Public Service Company of New Mexico [Member]
Electric Operating Revenues
Electric Operating Revenues	323,760	304,268	797,232	777,864
Operating Expenses:
Cost of energy	108,708	98,030	279,419	264,102
Administrative and general	37,916	42,107	110,833	117,291
Energy production costs	39,730	42,306	135,510	148,000
Regulatory disallowances	0	0	17,479	0
Depreciation and amortization	25,058	23,111	71,691	68,887
Transmission and distribution costs	11,848	9,819	35,357	29,450
Taxes other than income taxes	12,586	8,220	30,323	23,612
Total operating expenses	235,846	223,593	680,612	651,342
Operating income	87,914	80,675	116,620	126,522
Other Income and Deductions:
Interest income	3,770	4,523	12,052	14,538
Gains (losses) on investments held by NDT	(4,109)	2,206	7,688	2,606
Other income	1,179	807	1,921	11,989
Other deductions	(2,643)	(1,111)	(5,480)	(3,526)
Net other income (deductions)	(1,803)	6,425	16,181	25,607
Interest Charges	18,487	18,011	54,593	54,473
Earnings before Income Taxes	67,624	69,089	78,208	97,656
Income Taxes	25,052	25,926	26,574	34,748
Net Earnings	42,572	43,163	51,634	62,908
(Earnings) Attributable to Valencia Non-controlling Interest	(4,111)	(3,909)	(10,764)	(10,305)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(396)	(396)
Net Earnings Attributable to Company	38,461	39,254	40,870	52,603
Net Earnings (Loss) Available for Company Common Stock	38,329	39,122	40,474	52,207
Texas-New Mexico Power Company [Member]
Electric Operating Revenues
Non-affiliates	54,787	49,709	150,175	131,233
Affiliate	12,196	11,495	30,608	30,717
Total electric operating revenues	66,983	61,204	180,783	161,950
Operating Expenses:
Cost of energy	10,307	9,276	30,719	27,383
Administrative and general	9,998	9,620	29,798	27,932
Regulatory disallowances	0	0	3,923	0
Depreciation and amortization	12,674	11,594	33,662	31,728
Transmission and distribution costs	6,072	5,192	17,597	15,121
Taxes other than income taxes	6,381	5,899	16,113	15,481
Total operating expenses	45,432	41,581	131,812	117,645
Operating income	21,551	19,623	48,971	44,305
Other Income and Deductions:
Interest income	1	0	1	1
Other income	418	96	1,068	769
Other deductions	(105)	(8)	(181)	(52)
Net other income (deductions)	314	88	888	718
Interest Charges	7,276	7,661	21,880	23,483
Earnings before Income Taxes	14,589	12,050	27,979	21,540
Income Taxes	5,721	4,721	10,845	8,461
Net Earnings	$ 8,868	$ 7,329	$ 17,134	$ 13,079

XML

Variable Interest Entities (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 mw	Sep. 30, 2010	Dec. 31, 2010	May 30, 2008
Variable Interest Entity, Statement Of Operation [Abstract]
Earnings Attributable to non-controlling interest	$ 4,111,000	$ 3,909,000	$ 10,764,000	$ 10,305,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	625,738,000		625,738,000		543,880,000
Total assets	5,372,640,000	5,380,809,000	5,372,640,000	5,380,809,000	5,225,083,000
Current liabilities	712,649,000		712,649,000		520,124,000
Owners' equity - non-controlling interest	83,969,000		83,969,000		85,177,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member]
Variable Interest Entity [Line Items]
Operating Leases, Future Minimum Payments Due	105,100,000		105,100,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Property Lease Guarantee [Member] | Maximum [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Loss Contingency, Range of Possible Loss, Portion Not Accrued	178,300,000		178,300,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | PVNGS [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Future Minimum Payments Due, Current	11,800,000		11,800,000		26,000,000
Public Service Company of New Mexico [Member] | Valencia [Member]
Variable Interest Entity [Line Items]
Public Utilities, Power Plant Total Construction Costs						90,000,000
Long Term Contract For Purchase of Power Term of Contract			20 years
Long Term Contract for Purchase of Electric Power Plant, Estimated Total Output (in Megawatts)			145
Long Term Contract For Purchase of Electric Power Fixed Costs	4,600,000	4,600,000	13,700,000	13,500,000
Long Term Contract For Purchase of Electric Power Variable Charges	900,000	800,000	1,300,000	1,000,000
Variable Interest Entity, Statement Of Operation [Abstract]
Operating revenues	5,505,000	5,275,000	15,024,000	14,502,000
Operating expenses	(1,394,000)	(1,366,000)	(4,260,000)	(4,197,000)
Earnings Attributable to non-controlling interest	4,111,000	3,909,000	10,764,000	10,305,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	3,588,000		3,588,000		2,372,000
Net property, plant and equipment	81,493,000		81,493,000		83,617,000
Total assets	85,081,000		85,081,000		85,989,000
Current liabilities	1,112,000		1,112,000		812,000
Owners' equity - non-controlling interest	83,969,000		83,969,000		85,177,000
Public Service Company of New Mexico [Member] | Valencia [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Jointly Owned Utility Plant, Option to Purchase Proportionate Ownership Share	50.00%		50.00%
Valencia [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Future Minimum Payments Due, Current					26,000,000
Public Service Company of New Mexico [Member] | PVNGS [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Power Plant Operating Licenses Term			20 years
Public Service Company of New Mexico [Member] | Delta [Member]
Variable Interest Entity [Line Items]
Long Term Contract For Purchase of Electric Power Fixed Costs	1,500,000	1,500,000	4,500,000	4,500,000
Long Term Contract For Purchase of Electric Power Variable Charges	700,000	200,000	1,000,000	400,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Long Term Contract for Purchase of Electric Power Aggregate Amount of Contract Remaining	52,600,000		52,600,000
Public Service Company of New Mexico [Member]
Variable Interest Entity, Statement Of Operation [Abstract]
Earnings Attributable to non-controlling interest	4,111,000	3,909,000	10,764,000	10,305,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	387,312,000		387,312,000		384,038,000
Total assets	3,936,468,000		3,936,468,000		3,875,573,000
Current liabilities	438,578,000		438,578,000		394,961,000
Owners' equity - non-controlling interest	$ 83,969,000		$ 83,969,000		$ 85,177,000

XML

Capitalization, Line of Credit (Details) (USD $)	Oct. 31, 2011	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2009	Oct. 31, 2011 PNM Resources [Member]	Oct. 30, 2011 PNM Resources [Member] Revolving credit facility [Member]	Sep. 30, 2011 PNM Resources [Member] Revolving credit facility [Member]	Sep. 30, 2011 PNM Resources [Member] Local lines of credit [Member]	Oct. 31, 2011 Public Service Company of New Mexico [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member]	Sep. 30, 2010 Public Service Company of New Mexico [Member]	Dec. 31, 2009 Public Service Company of New Mexico [Member]	Oct. 31, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Oct. 30, 2011 Public Service Company of New Mexico [Member] Revolving credit facility [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Revolving credit facility [Member]	Oct. 31, 2011 Texas-New Mexico Power Company [Member]	Oct. 27, 2011 Texas-New Mexico Power Company [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member]	Dec. 31, 2010 Texas-New Mexico Power Company [Member]	Sep. 30, 2010 Texas-New Mexico Power Company [Member]	Dec. 31, 2009 Texas-New Mexico Power Company [Member]	Oct. 31, 2011 Texas-New Mexico Power Company [Member] Affiliated Entity [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Affiliated Entity [Member]	Sep. 30, 2011 Texas-New Mexico Power Company [Member] Revolving credit facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						$ 517,000,000		$ 5,000,000								$ 368,000,000										$ 75,000,000
Short-term Debt, Weighted Average Interest Rate							1.48%										0.88%
Line of Credit Facility, Remaining Borrowing Capacity	704,900,000				235,400,000				394,800,000									74,700,000
Cash and cash equivalents		25,760,000	25,097,000	14,641,000	166,700,000					5,034,000	10,336,000	8,991,000	1,373,000						0	9,000,000	1,000	96,000	138,000
Short-term debt – affiliate														$ 63,800,000	$ 0					$ 0	$ 1,200,000			$ 5,400,000	$ 0

XML

Related Party Transactions (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Electricity, transmission and distribution related services [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 12,196	$ 11,495	$ 30,608	$ 30,717
Service billings [Member] | PNM to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	40	100	327	379
Service billings [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	48	53	145	266
Service billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	24,680	26,373	70,849	69,948
Service billings [Member] | PNMR to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	7,295	6,798	21,250	19,090
Service billings [Member] | PNMR to Optim Energy [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	1,277	1,393	4,083	4,304
Service billings [Member] | Optim Energy to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	4	107	23	157
Income tax sharing payments [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	0	35,190
Interest charges [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	8	57	36	242
Interest charges [Member] | PNM to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	9	0	45	0
Interest charges [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 33	$ 0	$ 97	$ 0

XML

Fair Value of Derivative and Other Financial Instruments, Recurring (Details) (USD $) In Thousands	3 Months Ended			9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010	Sep. 30, 2011		Sep. 30, 2010	Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosure Derivative Reconciling Amount from Contract Value to Fair Value	$ 1,400			$ 1,400			$ 100
Fair Value, Level 1 to level 2 Transfers, Amount	0		0	0		0
Fair Value, Level 2 to level 1 Transfers, Amount	0		0	0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability Transfers Into Level 3	0		0	0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Transfers out of Level 3	0		0	0		0
Public Service Company of New Mexico [Member] | Commodity Contract [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	3,963	[1]		3,963	[1]		1,443	[1]
Commodity derivative instruments, Liabilities	(3,659)	[1]		(3,659)	[1]		(5,119)	[1]
Commodity derivative instruments, Net	304	[1]		304	[1]		(3,676)	[1]
Public Service Company of New Mexico [Member] | Commodity Contract [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			0
Commodity derivative instruments, Liabilities	0			0			0
Commodity derivative instruments, Net	0			0			0
Public Service Company of New Mexico [Member] | Commodity Contract [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	3,963			3,963			1,443
Commodity derivative instruments, Liabilities	(3,659)			(3,659)			(5,119)
Commodity derivative instruments, Net	304			304			(3,676)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	0			0			0
Commodity derivative instruments, Liabilities	0			0			0
Commodity derivative instruments, Net	0			0			0
Commodity Contract [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	41,232	[1]		41,232	[1]		21,263	[1]
Commodity derivative instruments, Liabilities	(57,391)	[1]		(57,391)	[1]		(44,238)	[1]
Commodity derivative instruments, Net	(16,159)	[1]		(16,159)	[1]		(22,975)	[1]
Commodity Contract [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	19,589			19,589			8,646
Commodity derivative instruments, Liabilities	(41,574)			(41,574)			(26,378)
Commodity derivative instruments, Net	(21,985)			(21,985)			(17,732)
Commodity Contract [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	18,982			18,982			12,308
Commodity derivative instruments, Liabilities	(14,094)			(14,094)			(16,729)
Commodity derivative instruments, Net	4,888			4,888			(4,421)
Commodity Contract [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	1,302			1,302			272
Commodity derivative instruments, Liabilities	(364)			(364)			(1,094)
Commodity derivative instruments, Net	938			938			(822)
Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosure Derivative Reconciling Amount from Contract Value to Fair Value	0			0			0
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]
NDT Investments	3,696	[1]		3,696	[1]		4,986	[1]
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]
NDT Investments	3,696			3,696			4,986
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]
NDT Investments	0			0			0
Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
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]
NDT Investments	22,051	[1]		22,051	[1]		25,491	[1]
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]
NDT Investments	22,051			22,051			25,491
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]
NDT Investments	0			0			0
Domestic value [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
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]
NDT Investments	47,358	[1]		47,358	[1]		48,237	[1]
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]
NDT Investments	47,358			47,358			48,237
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]
NDT Investments	0			0			0
Domestic growth [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Multinational [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	12,509	[1]		12,509	[1]		10,670	[1]
Multinational [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	12,509			12,509			10,670
Multinational [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Multinational [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
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]
NDT Investments	22,779	[1]		22,779	[1]		21,541	[1]
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]
NDT Investments	18,149			18,149			16,613
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]
NDT Investments	4,630			4,630			4,928
U.S. Government [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Municipals [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	39,316	[1]		39,316	[1]		37,595	[1]
Municipals [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Municipals [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	39,316			39,316			37,595
Municipals [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
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]
NDT Investments	9,292	[1]		9,292	[1]		8,402	[1]
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]
NDT Investments	0			0			0
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]
NDT Investments	9,292			9,292			8,402
Corporate and other [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	157,001	[1]		157,001	[1]		156,922	[1]
Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	103,763			103,763			105,997
Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	53,238			53,238			50,925
Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	$ 0			$ 0			$ 0

[1] The Level 1, 2 and 3 columns in the above table are presented based on the nature of each instrument. The total column is presented based on the balance sheet classification of the instruments and reflect unit of account reclassifications between commodity derivative assets and commodity derivative liabilities of $1.4 million for PNMR and zero for PNM at September 30, 2011 and less than $0.1 million for PNMR and zero for PNM at December 31, 2010. There were no transfers between levels for the three months and nine months ended September 30, 2011 and 2010.

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Fair Value of Derivative and Other Financial Instruments, Unobservable Input Reconciliation (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ 4,392	$ (278)	$ (822)	$ 248
Total gains (losses) included in earnings	(5,025)	(945)	201	(1,759)
Purchases	429	34	3,163	34
Settlements	1,142	(83)	(1,604)	205
Balance at end of period	938	(1,272)	938	(1,272)
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	589	(994)	1,455	(1,537)
Public Service Company of New Mexico [Member] | Electric operating revenues [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings	0	0	0	0
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	0	0	0	0
Electric operating revenues [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings	0	0	0	0
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	0	0	0	0
Public Service Company of New Mexico [Member] | Cost of energy [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings	0	0	0	(128)
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	0	0	0	0
Cost of energy [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings	(5,025)	(945)	201	(1,759)
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	589	(994)	1,455	(1,537)
Public Service Company of New Mexico [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	0	0	0	(17)
Total gains (losses) included in earnings	0	0	0	(128)
Purchases	0	0	0	0
Settlements	0	0	0	145
Balance at end of period	0	0	0	0
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	$ 0	$ 0	$ 0	$ 0

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Commitments and Contingencies (Details) (USD $)																				3 Months Ended		9 Months Ended						9 Months Ended										1 Months Ended	3 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Public Service Company of New Mexico [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member]	Oct. 31, 2010 Public Service Company of New Mexico [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Maximum [Member] Nuclear Plant [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Commercial Providers [Member] Nuclear Plant [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Industry Wide Retrospective Assessment Program [Member] Nuclear Plant [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Nuclear Plant [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Other Deferred Credits [Member] Nuclear Spent Fuel And Waste Disposal [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Other Deferred Credits [Member] Nuclear Spent Fuel And Waste Disposal [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Nuclear Spent Fuel And Waste Disposal [Member]	Jan. 06, 2010 Public Service Company of New Mexico [Member] Maximum [Member] San Juan Generating Station And Four Corners [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Maximum [Member] San Juan Generating Station [Member]	May 17, 2010 Public Service Company of New Mexico [Member] Maximum [Member] Citizen Suit Under the Clean Air Act [Member]	May 17, 2010 Public Service Company of New Mexico [Member] Maximum [Member] Mercury Control [Member]	Jan. 06, 2010 Public Service Company of New Mexico [Member] Minimum [Member] San Juan Generating Station And Four Corners [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Minimum [Member] San Juan Generating Station [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Surface [Member] San Juan Generating Station And Four Corners [Member] Loss on Long-term Purchase Commitment [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Sep. 30, 2010 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Sep. 30, 2010 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Underground [Member] San Juan Generating Station [Member] Loss on Long-term Purchase Commitment [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Underground [Member] Loss on Long-term Purchase Commitment [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Underground [Member] Loss on Long-term Purchase Commitment [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Coal Supply [Member] tons	Sep. 30, 2011 Public Service Company of New Mexico [Member] Coal Supply [Member] San Juan Generating Station [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Coal Supply [Member] San Juan Generating Station [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Clean Air Act related to SCR [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Clean Air Act Related to Sncr [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Four Corners [Member]	Feb. 10, 2011 Public Service Company of New Mexico [Member] Four Corners [Member]	Nov. 08, 2010 Public Service Company of New Mexico [Member] Four Corners [Member]	Sep. 30, 2011 Public Service Company of New Mexico [Member] Four Corners [Member] Clean Air Act related to Post-Combustion Controls [Member]	Jan. 31, 2011 Public Service Company of New Mexico [Member] Transmissions Issues [Member]	Sep. 30, 2011 Maximum [Member] Settlement Related To Gila River Indian Reservation Superfund Site [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss												$ 42,800,000			$ 42,000,000	$ 47,000,000			$ 53,400,000						$ 21,700,000								$ 77,000,000				$ 69,000,000
Public Utilities, Proposed Stack Opacity Limit																																		0.10
Loss Contingency Accrual, at Carrying Value										14,500,000	14,800,000									23,700,000		23,700,000		25,000,000		3,000,000	2,800,000
Loss Contingency, Range of Possible Loss, Minimum																																750,000,000
Loss Contingency, Range of Possible Loss, Maximum																																1,000,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share																															46.30%
Public Utilities, Government Proposed Emission Limit (pounds be MMBTU)					0.11																										0.05			0.098	0.098
Public Utilities, Government Standard Emission Limit (pounds per MMBTU, parts per million)			0.23										0.070				0.060														0.05
Public Utilities, Estimated Construction														897,000,000				749,000,000
Allowance For Funds Used During Construction														45,000,000				38,000,000
Public Utilities, Annual Increase in Costs Per Customer			85
Public Utilities, Proposed Opacity Limit Fugitive Dust Emission																																		0.20
Public Utilties, Jointly Owned Utility Plant, Sale of Ownership Percentage																																				48.00%
Other current assets	49,043,000	96,110,000	41,653,000	46,635,000																									17,800,000	30,900,000
Long-term Purchase Commitment, Minimum Quantity Required (tons of coal)																												44,200,000
Loss Contingency Accrual, Carrying Value, Payments																				1,300,000	900,000	3,600,000	3,500,000
Public Utilities, Liability Insurance Coverage						12,600,000,000	375,000,000	12,200,000,000
Public Utilities, Maximum Assessment Per Reactor For Each Incident									117,500,000
Public Utilities, Maximum Assessment Per Reactor For Each Incident, Annual Limit									17,500,000
Public Utilities, Ownership Percentage in Nuclear Reactor									10.20%
Public Utilities, Maximum Potential Assessment Per Incident									36,000,000
Public Utilities, Annual Payment Limitation Related to Incident									5,400,000
Public Utilities, Aggregate Amount of All Risk Insurance									2,750,000,000
Public Utilities, Maximum Amount under Nuclear Electir Insurance Limited									5,800,000
Litigation Settlement, Gross																																						$ 200,000	$ 100,000

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Sep. 30, 2011 PNM Electric [Member]	Sep. 30, 2010 PNM Electric [Member]	Sep. 30, 2011 PNM Electric [Member]	Sep. 30, 2010 PNM Electric [Member]	Sep. 30, 2011 TNMP Electric [Member]	Sep. 30, 2010 TNMP Electric [Member]	Sep. 30, 2011 TNMP Electric [Member]	Sep. 30, 2010 TNMP Electric [Member]	Sep. 30, 2011 First Choice [Member]	Sep. 30, 2010 First Choice [Member]	Sep. 30, 2011 First Choice [Member]	Sep. 30, 2010 First Choice [Member]	Sep. 30, 2011 Corporate and Other [Member]	Sep. 30, 2010 Corporate and Other [Member]	Sep. 30, 2011 Corporate and Other [Member]	Sep. 30, 2010 Corporate and Other [Member]	Sep. 30, 2010 Optim Energy [Member]	Sep. 30, 2011 Optim Energy [Member]	Sep. 30, 2010 Optim Energy [Member]	Sep. 23, 2011 Optim Energy [Member]	Sep. 22, 2011 Optim Energy [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage																									1.00%	50.00%
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues	$ 549,498	$ 503,653	$ 1,352,747	$ 1,292,865		$ 323,760	$ 304,268	$ 797,232	$ 777,864	$ 54,787	$ 49,709	$ 150,175	$ 131,233	$ 170,999	$ 149,729	$ 405,485	$ 384,034	$ (48)	$ (53)	$ (145)	$ (266)
Intersegment revenues	0	0	0	0		0	0	0	0	12,196	11,495	30,608	30,717	0	0	0	0	(12,196)	(11,495)	(30,608)	(30,717)
Total revenues	549,498	503,653	1,352,747	1,292,865		323,760	304,268	797,232	777,864	66,983	61,204	180,783	161,950	170,999	149,729	405,485	384,034	(12,244)	(11,548)	(30,753)	(30,983)
Cost of energy	250,854	215,169	582,814	557,238		108,708	98,030	279,419	264,102	10,307	9,276	30,719	27,383	144,035	119,358	303,285	296,469	(12,196)	(11,495)	(30,609)	(30,716)
Gross margin	298,644	288,484	769,933	735,627		215,052	206,238	517,813	513,762	56,676	51,928	150,064	134,567	26,964	30,371	102,200	87,565	(48)	(53)	(144)	(267)
Other operating expenses	147,990	144,096	457,454	432,430		102,080	102,452	329,502	318,353	22,451	20,711	67,431	58,534	25,076	23,952	67,693	65,652	(1,617)	(3,019)	(7,172)	(10,109)
Depreciation and amortization	42,370	38,980	119,115	113,634		25,058	23,111	71,691	68,887	12,674	11,594	33,662	31,728	346	210	987	683	4,292	4,065	12,775	12,336
Operating income	108,284	105,408	193,364	189,563		87,914	80,675	116,620	126,522	21,551	19,623	48,971	44,305	1,542	6,209	33,520	21,230	(2,723)	(1,099)	(5,747)	(2,494)
Interest income	3,748	4,499	12,010	14,608		3,770	4,523	12,052	14,538	1	0	1	1	29	3	63	16	(52)	(27)	(106)	53
Equity in net earnings (loss) of Optim Energy	0	2,495	0	(5,714)			0		0		0		0		0		0		2,495		(5,714)	2,500	0	(5,700)
Other income (deductions)	(7,039)	321	(391)	7,078		(5,573)	1,902	4,129	11,069	313	88	887	717	(115)	(66)	(494)	(164)	(1,664)	(1,603)	(4,913)	(4,544)
Net interest charges	(31,124)	(31,317)	(92,251)	(94,488)		(18,487)	(18,011)	(54,593)	(54,473)	(7,276)	(7,661)	(21,880)	(23,483)	(249)	(364)	(535)	(1,062)	(5,112)	(5,281)	(15,243)	(15,470)
Earnings before Income Taxes	73,869	81,406	112,732	111,047		67,624	69,089	78,208	97,656	14,589	12,050	27,979	21,540	1,207	5,782	32,554	20,020	(9,551)	(5,515)	(26,009)	(28,169)
Income taxes (benefit)	25,964	28,813	37,206	37,365		25,052	25,926	26,574	34,748	5,721	4,721	10,845	8,461	594	2,225	11,833	7,363	(5,403)	(4,059)	(12,046)	(13,207)
Net earnings	47,905	52,593	75,526	73,682		42,572	43,163	51,634	62,908	8,868	7,329	17,134	13,079	613	3,557	20,721	12,657	(4,148)	(1,456)	(13,963)	(14,962)
Valencia non-controlling interest	(4,111)	(3,909)	(10,764)	(10,305)		(4,111)	(3,909)	(10,764)	(10,305)	0	0	0	0	0	0	0	0	0	0	0	0
Subsidiary preferred stock dividends	(132)	(132)	(396)	(396)		(132)	(132)	(396)	(396)	0	0	0	0	0	0	0	0	0	0	0	0
Net Earnings Attributable to PNMR	43,662	48,552	64,366	62,981		38,329	39,122	40,474	52,207	8,868	7,329	17,134	13,079	613	3,557	20,721	12,657	(4,148)	(1,456)	(13,963)	(14,962)
Total Assets	5,372,640	5,380,809	5,372,640	5,380,809	5,225,083	3,936,468	3,812,829	3,936,468	3,812,829	1,041,613	1,004,785	1,041,613	1,004,785	274,741	259,621	274,741	259,621	119,818	303,574	119,818	303,574
Goodwill	321,310	321,310	321,310	321,310		51,632	51,632	51,632	51,632	226,665	226,665	226,665	226,665	43,013	43,013	43,013	43,013	0	0	0	0
Additions to utility and non-utility plant included in accounts payable	$ 11,842		$ 11,842			$ 6,811		$ 6,811		$ 4,672		$ 4,672		$ 106		$ 106		$ 253		$ 253