TEXAS NEW MEXICO POWER CO - FORM 10-Q

Attached files

file	filename
EX-4.2 - EXHIBIT 4.2 - TEXAS NEW MEXICO POWER CO	pnm6302011ex42.htm
EX-4.1 - EXHIBIT 4.1 - TEXAS NEW MEXICO POWER CO	pnm6302011ex41.htm
EX-4.3 - EXHBITI 4.3 - TEXAS NEW MEXICO POWER CO	pnm6302011ex43.htm
EX-4.4 - EXHIBIT 4.4 - TEXAS NEW MEXICO POWER CO	pnm6302011ex44.htm
EX-12.1 - EXHIBIT 12.1 - TEXAS NEW MEXICO POWER CO	pnm6302011ex121.htm
EX-12.4 - EXHIBIT 12.4 - TEXAS NEW MEXICO POWER CO	pnm6302011ex124.htm
EX-31.3 - TEXAS NEW MEXICO POWER CO	pnm6302011ex313.htm
EX-32.2 - TEXAS NEW MEXICO POWER CO	pnm6302011ex322.htm
EX-31.4 - TEXAS NEW MEXICO POWER CO	pnm6302011ex314.htm
EX-12.2 - EXHIBIT 12.2 - TEXAS NEW MEXICO POWER CO	pnm6302011ex122.htm
EX-31.5 - TEXAS NEW MEXICO POWER CO	pnm6302011ex315.htm
EX-31.6 - TEXAS NEW MEXICO POWER CO	pnm6302011ex316.htm
EX-12.3 - EXHIBIT 12.3 - TEXAS NEW MEXICO POWER CO	pnm6302011ex123.htm
EX-31.1 - TEXAS NEW MEXICO POWER CO	pnm6302011ex311.htm
EX-32.1 - TEXAS NEW MEXICO POWER CO	pnm6302011ex321.htm
EX-32.3 - TEXAS NEW MEXICO POWER CO	pnm6302011ex323.htm
EX-31.2 - TEXAS NEW MEXICO POWER CO	pnm6302011ex312.htm
EX-10.1 - EXHIBIT 10.1 - TEXAS NEW MEXICO POWER CO	pnm6302011ex101.htm

Table of Contents

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 June 30, 2011



Commission File Number	Name of Registrants, State of Incorporation, Address and Telephone Number	I.R.S. Employer 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		NO
TNMP	YES		NO

Table of Contents

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

PNM

TNMP

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 August 2, 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 August 2, 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 August 2, 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.

Table of Contents

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	6
Condensed Consolidated Balance Sheets	7
Condensed Consolidated Statements of Cash Flows	9
Condensed Consolidated Statements of Changes in Equity	11
Condensed Consolidated Statements of Comprehensive Income	12
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings (Loss)	13
Condensed Consolidated Balance Sheets	14
Condensed Consolidated Statements of Cash Flows	16
Condensed Consolidated Statements of Changes in Equity	18
Condensed Consolidated Statements of Comprehensive Income (Loss)	19
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	20
Condensed Consolidated Balance Sheets	21
Condensed Consolidated Statements of Cash Flows	23
Condensed Consolidated Statements of Changes in Equity	25
Condensed Consolidated Statements of Comprehensive Income	26
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	71
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	94
ITEM 4. CONTROLS AND PROCEDURES	98
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	99
ITEM 1A. RISK FACTORS	99
ITEM 6. EXHIBITS	100
SIGNATURE	102

Table of Contents

GLOSSARY



Definitions:
Afton	Afton Generating Station
ABCWUA	Albuquerque Bernalillo County Water Utility Authority
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
Cascade	Cascade Investment, L.L.C.
CCB	Coal Combustion Byproducts
CO₂	Carbon Dioxide
Cogen	Optim Energy Altura Cogen, LLC (the CoGen Lyondell Power Generation Facility)
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.
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

Table of Contents



NERC	North American Electric Reliability Council
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
PNMR	PNM Resources, Inc. and Subsidiaries
PNMR Facility	PNMR’s 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
S&P	Standard and Poor’s Ratings Services
TECA	Texas Electric Choice Act
Term Loan Agreement	PNM’s $300 Million Unsecured Delayed Draw Term Loan Facility
TNMP	Texas-New Mexico Power Company and Subsidiaries
TNMP Revolving Credit Facility	TNMP’s $75 Million Revolving Credit Facility
Twin Oaks	Optim Energy Twin Oaks, LP
Valencia	Valencia Energy Facility
VaR	Value at Risk
WACC	Weighted Average Cost of Capital

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands, except per share amounts)
Electric Operating Revenues	$	415,586		$	405,817		$	803,249		$	789,212
Operating Expenses:
Cost of energy	173,454			151,181			331,961			342,069
Administrative and general	68,795			62,420			127,260			125,205
Energy production costs	47,127			51,811			95,779			105,696
Regulatory disallowances	21,402			—			21,402			—
Depreciation and amortization	38,272			37,376			76,745			74,655
Transmission and distribution costs	18,161			15,672			35,038			29,562
Taxes other than income taxes	15,515			13,683			29,985			27,869
Total operating expenses	382,726			332,143			718,170			705,056
Operating income	32,860			73,674			85,079			84,156
Other Income and Deductions:
Interest income	4,234			5,083			8,261			10,110
Gains (losses) on investments held by NDT	5,894			(1,342		)	11,797			400
Other income	809			1,171			1,804			11,370
Equity in net earnings (loss) of Optim Energy	—			(3,858		)	—			(8,210		)
Other deductions	(3,881		)	(3,173		)	(6,953		)	(5,014		)
Net other income (deductions)	7,056			(2,119		)	14,909			8,656
Interest Charges	30,512			31,761			61,127			63,171
Earnings before Income Taxes	9,404			39,794			38,861			29,641
Income Taxes	1,735			13,492			11,241			8,552
Net Earnings	7,669			26,302			27,620			21,089
(Earnings) Attributable to Valencia Non-controlling Interest	(3,470		)	(3,292		)	(6,652		)	(6,396		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(264		)	(264		)
Net Earnings Attributable to PNMR	$	4,067		$	22,878		$	20,704		$	14,429
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.04		$	0.25		$	0.23		$	0.16
Diluted	$	0.04		$	0.25		$	0.22		$	0.16
Dividends Declared per Common Share	$	0.125		$	0.125		$	0.250		$	0.250

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

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2011		December 31, 2010
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	14,023	$	15,404
Accounts receivable, net of allowance for uncollectible accounts of $9,275 and $11,178	103,824		97,245
Unbilled revenues	97,513		71,453
Other receivables	46,596		58,901
Affiliate receivables	2,392		1,661
Materials, supplies, and fuel stock	51,370		52,479
Regulatory assets	29,608		36,292
Commodity derivative instruments	18,840		15,999
Income taxes receivable	102,317		97,450
Current portion of accumulated deferred income taxes	886		886
Other current assets	99,919		96,110
Total current assets	567,288		543,880
Other Property and Investments:
Investment in PVNGS lessor notes	90,555		103,871
Investments held by NDT	168,513		156,922
Other investments	15,645		18,791
Non-utility property, net of accumulated depreciation of $2,333 and $2,307	12,317		7,333
Total other property and investments	287,030		286,917
Utility Plant:
Plant in service and plant held for future use	4,959,239		4,860,614
Less accumulated depreciation and amortization	1,665,970		1,626,693
	3,293,269		3,233,921
Construction work in progress	139,340		137,622
Nuclear fuel, net of accumulated amortization of $29,993 and $26,247	79,906		72,901
Net utility plant	3,512,515		3,444,444
Deferred Charges and Other Assets:
Regulatory assets	478,599		502,467
Goodwill	321,310		321,310
Other intangible assets, net of accumulated amortization of $5,511 and $5,414	26,329		26,425
Commodity derivative instruments	7,754		5,264
Other deferred charges	100,808		94,376
Total deferred charges and other assets	934,800		949,842
	$	5,301,633	$	5,225,083

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

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2011			December 31, 2010
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	304,000		$	222,000
Current installments of long-term debt	2,252			2,252
Accounts payable	111,460			95,969
Accrued interest and taxes	45,852			47,783
Regulatory liabilities	919			724
Commodity derivative instruments	27,285			31,407
Dividends declared	132			11,565
Other current liabilities	97,547			108,424
Total current liabilities	589,447			520,124
Long-term Debt	1,563,916			1,563,595
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	543,044			540,106
Accumulated deferred investment tax credits	16,930			18,089
Regulatory liabilities	358,141			342,465
Asset retirement obligations	75,483			76,637
Accrued pension liability and postretirement benefit cost	250,671			270,172
Commodity derivative instruments	13,770			12,831
Other deferred credits	149,610			147,616
Total deferred credits and other liabilities	1,407,649			1,407,916
Total liabilities	3,561,012			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 477,800 shares)	100,000			100,000
PNMR common stockholders’ equity:
Common stock outstanding (no par value, 120,000,000 shares authorized: issued and outstanding 86,673,174 shares)	1,290,969			1,290,465
Accumulated other comprehensive income (loss), net of income taxes	(70,691		)	(68,666		)
Retained earnings	324,217			314,943
Total PNMR common stockholders’ equity	1,544,495			1,536,742
Non-controlling interest in Valencia	84,597			85,177
Total equity	1,729,092			1,721,919
	$	5,301,633		$	5,225,083

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

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	27,620		$	21,089
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	97,404			89,608
PVNGS firm-sales contract revenue	(2,558		)	(28,856		)
Bad debt expense	11,732			13,035
Deferred income tax expense	17,992			15,649
Equity in net (earnings) loss of Optim Energy	—			8,210
Net unrealized (gains) losses on derivatives	(6,996		)	24,752
Realized (gains) on investments held by NDT	(11,797		)	(400		)
Stock based compensation expense	2,867			1,962
Regulatory disallowances	21,402			—
Other, net	2,115			2,288
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(44,371		)	(23,643		)
Materials, supplies, and fuel stock	1,109			(1,615		)
Other current assets	1,679			(34,909		)
Other assets	(257		)	(5,739		)
Accounts payable	6,101			(476		)
Accrued interest and taxes	(6,798		)	55,024
Other current liabilities	(10,532		)	(44,694		)
Other liabilities	(21,972		)	(15,083		)
Net cash flows from operating activities	84,740			76,202

Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(153,168		)	(136,296		)
Proceeds from sales of investments held by NDT	94,890			36,285
Purchases of investments held by NDT	(96,410		)	(37,850		)
Return of principal on PVNGS lessor notes	15,374			14,216
Investments in Optim Energy	—			(16,407		)
Other, net	760			1,416
Net cash flows from investing activities	(138,554		)	(138,636		)

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

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	82,000			87,000
Long-term borrowings	—			403,845
Repayment of long-term debt	—			(403,845		)
Proceeds from stock option exercise	2,172			778
Purchases to satisfy awards of common stock	(4,535		)	(2,269		)
Excess tax (shortfall) from stock-based payment arrangements	—			(114		)
Dividends paid	(23,127		)	(23,127		)
Equity transactions with Valencia’s owner	(7,232		)	(7,019		)
Payments received on PVNGS firm-sales contracts	2,558			15,233
Proceeds from transmission interconnection agreements	589			—
Debt issuance costs and other	8			(3,592		)
Net cash flows from financing activities	52,433			66,890

Change in Cash and Cash Equivalents	(1,381		)	4,456
Cash and Cash Equivalents at Beginning of Period	15,404			14,641
Cash and Cash Equivalents at End of Period	$	14,023		$	19,097

Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	57,930		$	61,188
Income taxes paid (refunded), net	$	(1,775	)	$	(63,408	)

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

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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
			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	—		2,172			—			—			2,172			—			2,172
Purchases to satisfy awards of common stock	—		(4,535		)	—			—			(4,535		)	—			(4,535		)
Stock based compensation expense	—		2,867			—			—			2,867			—			2,867
Valencia’s transactions with its owner	—		—			—			—			—			(7,232		)	(7,232		)
Net earnings before subsidiary preferred stock dividends	—		—			—			20,968			20,968			6,652			27,620
Subsidiary preferred stock dividends	—		—			—			(264		)	(264		)	—			(264		)
Total other comprehensive income (loss)	—		—			(2,025		)	—			(2,025		)	—			(2,025		)
Dividends declared on common stock	—		—			—			(11,430		)	(11,430		)	—			(11,430		)
Balance at June 30, 2011	$	100,000	$	1,290,969		$	(70,691	)	$	324,217		$	1,544,495		$	84,597		$	1,729,092

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

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(In thousands)
Net Earnings	$	7,669		$	26,302		$	27,620		$	21,089
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 $(5,827), $1,280, $(9,280), and $58	8,892			(1,953		)	14,161			(88		)
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $7,892, $720, $9,962, and $1,330	(12,043		)	(1,098		)	(15,201		)	(2,029		)
Pension liability adjustment, net of income tax (expense) benefit of $(425), $0, $601, and $147	648			—			(966		)	(223		)
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $327, $1,197, $318, and $(3,859)	(585		)	(1,978		)	(562		)	5,639
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(215), $4,035, $(302), and $8,227	389			(6,055		)	543			(12,370		)
Total Other Comprehensive Income (Loss)	(2,699		)	(11,084		)	(2,025		)	(9,071		)
Comprehensive Income	4,970			15,218			25,595			12,018
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,470		)	(3,292		)	(6,652		)	(6,396		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(264		)	(264		)
Comprehensive Income Attributable to PNMR	$	1,368		$	11,794		$	18,679		$	5,358

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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands)
Electric Operating Revenues	$	239,234		$	243,060		$	473,472		$	473,596
Operating Expenses:
Cost of energy	81,497			79,639			170,711			166,073
Administrative and general	38,580			37,498			72,916			75,184
Energy production costs	47,127			51,809			95,779			105,694
Regulatory disallowances	17,479			—			17,479			—
Depreciation and amortization	22,897			22,924			46,632			45,776
Transmission and distribution costs	11,902			10,323			23,509			19,631
Taxes other than income taxes	9,209			7,477			17,740			15,391
Total operating expenses	228,691			209,670			444,766			427,749
Operating income	10,543			33,390			28,706			45,847
Other Income and Deductions:
Interest income	4,225			5,081			8,282			10,015
Gains (losses) on investments held by NDT	5,894			(1,342		)	11,797			400
Other income	441			1,145			742			11,182
Other deductions	(1,851		)	(1,794		)	(2,837		)	(2,415		)
Net other income (deductions)	8,709			3,090			17,984			19,182
Interest Charges	18,027			18,385			36,107			36,462
Earnings before Income Taxes	1,225			18,095			10,583			28,567
Income Taxes (Benefit)	(872		)	5,901			1,522			8,822
Net Earnings	2,097			12,194			9,061			19,745
(Earnings) Attributable to Valencia Non-controlling Interest	(3,470		)	(3,292		)	(6,652		)	(6,396		)
Net Earnings (Loss) Attributable to PNM	(1,373		)	8,902			2,409			13,349
Preferred Stock Dividends Requirements	(132		)	(132		)	(264		)	(264		)
Net Earnings (Loss) Available for PNM Common Stock	$	(1,505	)	$	8,770		$	2,145		$	13,085

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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2011		December 31, 2010
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	485	$	10,336
Accounts receivable, net of allowance for uncollectible accounts of $1,483 and $1,483	53,121		58,785
Unbilled revenues	52,200		39,053
Other receivables	45,494		56,951
Affiliate receivables	9,053		8,605
Materials, supplies, and fuel stock	48,624		49,454
Regulatory assets	26,344		35,835
Commodity derivative instruments	935		1,443
Income taxes receivable	82,662		76,941
Other current assets	49,185		46,635
Total current assets	368,103		384,038
Other Property and Investments:
Investment in PVNGS lessor notes	90,555		103,871
Investments held by NDT	168,513		156,922
Other investments	4,118		5,068
Non-utility property	976		976
Total other property and investments	264,162		266,837
Utility Plant:
Plant in service and plant held for future use	3,898,460		3,818,722
Less accumulated depreciation and amortization	1,283,394		1,259,957
	2,615,066		2,558,765
Construction work in progress	121,238		115,628
Nuclear fuel, net of accumulated amortization of $29,993 and $26,247	79,906		72,901
Net utility plant	2,816,210		2,747,294
Deferred Charges and Other Assets:
Regulatory assets	345,728		357,944
Goodwill	51,632		51,632
Commodity derivative instruments	5		—
Other deferred charges	74,314		67,828
Total deferred charges and other assets	471,679		477,404
	$	3,920,154	$	3,875,573

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

Table of Contents

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2011			December 31, 2010
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	273,000		$	190,000
Accounts payable	57,003			51,931
Affiliate payables	17,862			8,528
Accrued interest and taxes	27,298			25,773
Regulatory liabilities	919			724
Commodity derivative instruments	1,720			3,110
Dividends declared	3,781			39,254
Current portion of accumulated deferred income taxes	9,783			9,783
Other current liabilities	64,281			65,858
Total current liabilities	455,647			394,961
Long-term Debt	1,055,756			1,055,748
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	440,579			446,657
Accumulated deferred investment tax credits	16,930			18,089
Regulatory liabilities	316,109			299,763
Asset retirement obligations	74,707			75,888
Accrued pension liability and postretirement benefit cost	235,737			253,948
Commodity derivative instruments	1,841			2,009
Other deferred credits	111,122			108,455
Total deferred credits and liabilities	1,197,025			1,204,809
Total liabilities	2,708,428			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	(68,468		)	(66,786		)
Retained earnings	165,292			171,359
Total PNM common stockholder’s equity	1,115,600			1,123,349
Non-controlling interest in Valencia	84,597			85,177
Total equity	1,200,197			1,208,526
	$	3,920,154		$	3,875,573

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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	9,061		$	19,745
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	63,077			56,975
PVNGS firm-sales contract revenue	(2,558		)	(28,856		)
Deferred income tax expense	8,784			18,777
Net unrealized (gains) losses on derivatives	(1,453		)	5,605
Realized (gains) losses on investments held by NDT	(11,797		)	(400		)
Regulatory disallowances	17,479			—
Other, net	3,432			4,030
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(8,796		)	1,845
Materials, supplies, and fuel stock	830			(1,154		)
Other current assets	7,467			(17,477		)
Other assets	3,301			3,395
Accounts payable	(2,791		)	2,315
Accrued interest and taxes	(4,196		)	24,721
Other current liabilities	6,730			(44,593		)
Other liabilities	(22,339		)	(14,521		)
Net cash flows from operating activities	66,231			30,407

Cash Flows From Investing Activities:
Utility plant additions	(125,939		)	(118,467		)
Proceeds from sales of NDT investments	94,890			36,285
Purchases of NDT investments	(96,410		)	(37,850		)
Return of principal on PVNGS lessor notes	15,374			14,216
Other, net	1,037			945
Net cash flows from investing activities	(111,048		)	(104,871		)

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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	83,000			74,000
Long-term borrowings	—			403,845
Repayment of long-term debt	—			(403,845		)
Payments received on PVNGS firm-sales contracts	2,558			15,233
Equity transactions with Valencia’s owner	(7,232		)	(7,019		)
Proceeds from transmission interconnection arrangements	589			—
Dividends paid	(43,949		)	(264		)
Debt issuance costs and other	—			(3,118		)
Net cash flows from financing activities	34,966			78,832
Change in Cash and Cash Equivalents	(9,851		)	4,368
Cash and Cash Equivalents at Beginning of Period	10,336			1,373
Cash and Cash Equivalents at End of Period	$	485		$	5,741
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	35,081		$	37,656
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.

Table of Contents

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
	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	—		—			—			—			(7,232		)	(7,232		)
Net earnings	—		—			2,409			2,409			6,652			9,061
Total other comprehensive income (loss)	—		(1,682		)	—			(1,682		)	—			(1,682		)
Dividends declared on preferred stock	—		—			(264		)	(264		)	—			(264		)
Dividends declared on common stock	—		—			(8,212		)	(8,212		)	—			(8,212		)
Balance at June 30, 2011	$	1,018,776	$	(68,468	)	$	165,292		$	1,115,600		$	84,597		$	1,200,197

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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
				(In thousands)
Net Earnings	$	2,097		$	12,194		$	9,061		$	19,745
Other Comprehensive Income (Loss):
Unrealized Gain on Investment Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit of $(5,827), $1,280, $(9,280), and $58	8,892			(1,953		)	14,161			(88		)
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $7,892, $720, $9,962, and $1,330	(12,043		)	(1,098		)	(15,201		)	(2,029		)
Pension liability adjustment, net of income tax (expense) benefit of $(423), $0, $432 and $147	646			—			(659		)	(223		)
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $(71), $0, and $(2,767)	—			109			—			4,223
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $0, $2,540, $(11), and $5,210	—			(3,876		)	17			(7,950		)
Total Other Comprehensive Income (Loss)	(2,505		)	(6,818		)	(1,682		)	(6,067		)
Comprehensive Income (Loss)	(408		)	5,376			7,379			13,678
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,470		)	(3,292		)	(6,652		)	(6,396		)
Comprehensive Income (Loss) Attributable to PNM	$	(3,878	)	$	2,084		$	727		$	7,282

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
				(In thousands)
Electric Operating Revenues:
Non-affiliates	$	50,359		$	42,934		$	95,387		$	81,525
Affiliate	9,598			9,635			18,412			19,221
Total electric operating revenues	59,957			52,569			113,799			100,746
Operating Expenses:
Cost of energy	10,259			9,057			20,412			18,107
Administrative and general	10,135			8,818			19,801			18,312
Regulatory disallowances	3,923			—			3,923			—
Depreciation and amortization	10,726			10,040			20,987			20,135
Transmission and distribution costs	6,256			5,348			11,524			9,929
Taxes other than income taxes	4,963			4,865			9,733			9,581
Total operating expenses	46,262			38,128			86,380			76,064
Operating income	13,695			14,441			27,419			24,682
Other Income and Deductions:
Other income	288			309			650			673
Other deductions	(29		)	(26		)	(75		)	(43		)
Net other income (deductions)	259			283			575			630
Interest Charges	7,305			7,953			14,604			15,822
Earnings Before Income Taxes	6,649			6,771			13,390			9,490
Income Taxes	2,547			2,665			5,125			3,740
Net Earnings	$	4,102		$	4,106		$	8,265		$	5,750

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2011		December 31, 2010
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable	16,740		12,742
Unbilled revenues	7,534		5,734
Other receivables	1,208		1,677
Affiliate receivables	5,316		3,956
Materials and supplies	2,713		2,787
Regulatory assets	3,264		457
Current portion of accumulated deferred income taxes	1,876		1,876
Other current assets	1,265		618
Total current assets	39,917		29,848
Other Property and Investments:
Other investments	268		282
Non-utility property	2,240		2,244
Total other property and investments	2,508		2,526
Utility Plant:
Plant in service and plant held for future use	903,429		885,325
Less accumulated depreciation and amortization	313,482		302,333
	589,947		582,992
Construction work in progress	14,043		12,375
Net utility plant	603,990		595,367
Deferred Charges and Other Assets:
Regulatory assets	132,871		144,522
Goodwill	226,665		226,665
Other deferred charges	12,474		12,029
Total deferred charges and other assets	372,010		383,216
	$	1,018,425	$	1,010,957

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2011			December 31, 2010
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt – affiliate	$	7,000		$	1,200
Accounts payable	5,507			5,537
Affiliate payables	3,306			1,015
Accrued interest and taxes	17,150			23,185
Other current liabilities	4,016			3,292
Total current liabilities	36,979			34,229
Long-term Debt	310,650			310,337
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	146,692			142,121
Regulatory liabilities	42,032			42,702
Asset retirement obligations	671			648
Accrued pension liability and postretirement benefit cost	14,934			16,224
Other deferred credits	12,418			11,413
Total deferred credits and other liabilities	216,747			213,108
Total liabilities	564,376			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	(1,918		)	(1,485		)
Retained earnings	32,861			24,596
Total common stockholder’s equity	454,049			453,283
	$	1,018,425		$	1,010,957

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	8,265		$	5,750
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	22,569			22,147
Deferred income tax expense (benefit)	4,805			(3,444		)
Regulatory disallowances	3,923			—
Other, net	31			(633		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(5,798		)	(3,240		)
Materials and supplies	74			(494		)
Other current assets	(2,243		)	(1,153		)
Other assets	(657		)	(1,730		)
Accounts payable	(154		)	(1,552		)
Accrued interest and taxes	(6,034		)	1,598
Other current liabilities	1,628			(1,391		)
Other liabilities	(1,078		)	(689		)
Net cash flows from operating activities	25,331			15,169
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(24,072		)	(13,967		)
Net cash flows from investing activities	(24,072		)	(13,967		)

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net – affiliate	5,800			500
Dividends paid	(7,066		)	(1,644		)
Debt issuance costs and other	7			(124		)
Net cash flows from financing activities	(1,259		)	(1,268		)
Change in Cash and Cash Equivalents	—			(66		)
Cash and Cash Equivalents at Beginning of Period	1			138
Cash and Cash Equivalents at End of Period	$	1		$	72
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	13,852		$	14,050
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.

Table of Contents

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	—		—			—			8,265		8,265
Total other comprehensive income (loss)	—		—			(433		)	—		(433		)
Dividends declared on common stock	—		(7,066		)	—			—		(7,066		)
Balance at June 30, 2011	$	64	$	423,042		$	(1,918	)	$	32,861	$	454,049

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

Table of Contents

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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(In thousands)
Net Earnings	$	4,102		$	4,106		$	8,265		$	5,750
Other Comprehensive Income (Loss):
Pension liability adjustment, net of income tax (expense) benefit of $(1), $0, $170, and $0	2			—			(307		)	—
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $307, $541, $272, and $891	(555		)	(976		)	(491		)	(1,607		)
Reclassification adjustment for losses included in net earnings, net of income tax (benefit) of $(102), $(103), $(202), and $(205)	184			186			365			371
Total Other Comprehensive Income (Loss)	(369		)	(790		)	(433		)	(1,236		)
Comprehensive Income	$	3,733		$	3,316		$	7,832		$	4,514

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

Table of Contents

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 June 30, 2011 and December 31, 2010, and the consolidated results of operations and comprehensive income for the three months and six months ended June 30, 2011 and 2010, and cash flows for the six months ended June 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. See Note 16.

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. 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. All intercompany transactions and balances have been eliminated. See Note 12.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.125 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.

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 no dividends on its common stock in the six months ended June 30, 2010. TNMP declared and paid cash dividends to PNMR of $7.1 million and $1.6 million in the six months ended June 30, 2011 and 2010. TNMP dividends were recorded as reductions of its paid-in-capital.

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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)

(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 six months ended June 30, 2011, PNM paid $4.6 million and $9.1 million for fixed charges and $0.3 million and $0.4 million for variable charges. For the three months and six months ended June 30, 2010, PNM paid $4.5 million and $9.0 million for fixed charges and $0.2 million and $0.3 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy 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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
				(In thousands)
Operating revenues	$	4,849		$	4,725		$	9,519		$	9,227
Operating expenses	(1,379		)	(1,433		)	(2,867		)	(2,831		)
Earnings attributable to non-controlling interest	$	3,470		$	3,292		$	6,652		$	6,396

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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)

Financial Position



	June 30,		December 31,
	2011		2010
	(In thousands)
Current assets	$	3,158	$	2,372
Net property, plant and equipment	82,200		83,617
Total assets	85,358		85,989
Current liabilities	761		812
Owners’ equity – non-controlling interest	$	84,597	$	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 $111.4 million as of June 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 June 30, 2011, PNM could have been required to pay the beneficial owners up to approximately $177.0 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 $26.0 million at June 30, 2011 and 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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 six months ended June 30, 2011, PNM incurred fixed payments of $1.5 million and $2.9 million and variable payments of less than $0.1 million and $0.3 million under the PPA. For the three months and six months ended June 30, 2010, PNM incurred fixed payments of $1.7 million and $3.0 million and variable payments of less than $0.1 million and $0.2 million under the PPA. PNM’s only quantifiable obligation under the PPA is to make the fixed payments, which as of June 30, 2011, aggregated $54.1 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 as well as 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 excluded from retail rates. FERC has jurisdiction over wholesale 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.

Optim Energy

Optim Energy is considered a separate segment for PNMR. PNMR’s investment in Optim Energy is held in the Corporate and Other segment and is accounted for using the equity method of accounting. Optim Energy’s revenues and expenses are not included in PNMR’s consolidated revenues and expenses or the following tables. As described in Note 11, PNMR fully impaired its investment in Optim Energy as of December 31, 2010.

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.

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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)

PNMR SEGMENT INFORMATION



	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended June 30, 2011	(In thousands)
Operating revenues	$	239,234		$	50,359		$	126,036		$	(43	)	$	415,586
Intersegment revenues	—			9,598			—			(9,598		)	—
Total revenues	239,234			59,957			126,036			(9,641		)	415,586
Cost of energy	81,497			10,259			91,296			(9,598		)	173,454
Gross margin	157,737			49,698			34,740			(43		)	242,132
Other operating expenses	124,297			25,277			23,630			(2,204		)	171,000
Depreciation and amortization	22,897			10,726			360			4,289			38,272
Operating income (loss)	10,543			13,695			10,750			(2,128		)	32,860
Interest income	4,225			—			31			(22		)	4,234
Other income (deductions)	4,484			259			(273		)	(1,648		)	2,822
Net interest charges	(18,027		)	(7,305		)	(141		)	(5,039		)	(30,512		)
Segment earnings (loss) before income taxes	1,225			6,649			10,367			(8,837		)	9,404
Income taxes (benefit)	(872		)	2,547			3,745			(3,685		)	1,735
Segment earnings (loss)	2,097			4,102			6,622			(5,152		)	7,669
Valencia non-controlling interest	(3,470		)	—			—			—			(3,470		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	(1,505	)	$	4,102		$	6,622		$	(5,152	)	$	4,067

Six Months Ended June 30, 2011
Operating revenues	$	473,472		$	95,387		$	234,486		$	(96	)	$	803,249
Intersegment revenues	—			18,412			—			(18,412		)	—
Total revenues	473,472			113,799			234,486			(18,508		)	803,249
Cost of energy	170,711			20,412			159,250			(18,412		)	331,961
Gross margin	302,761			93,387			75,236			(96		)	471,288
Other operating expenses	227,423			44,981			42,616			(5,556		)	309,464
Depreciation and amortization	46,632			20,987			641			8,485			76,745
Operating income (loss)	28,706			27,419			31,979			(3,025		)	85,079
Interest income	8,282			—			34			(55		)	8,261
Other income (deductions)	9,702			575			(379		)	(3,250		)	6,648
Net interest charges	(36,107		)	(14,604		)	(286		)	(10,130		)	(61,127		)
Segment earnings (loss) before income taxes	10,583			13,390			31,348			(16,460		)	38,861
Income taxes (benefit)	1,522			5,125			11,237			(6,643		)	11,241
Segment earnings (loss)	9,061			8,265			20,111			(9,817		)	27,620
Valencia non-controlling interest	(6,652		)	—			—			—			(6,652		)
Subsidiary preferred stock dividends	(264		)	—			—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	2,145		$	8,265		$	20,111		$	(9,817	)	$	20,704
At June 30, 2011:
Total Assets	$	3,920,154		$	1,018,425		$	254,352		$	108,702		$	5,301,633
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310
Additions to utility and non-utility plant included in accounts payable	$	16,514		$	360		$	237		$	1,165		$	18,276

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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)



	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended June 30, 2010	(In thousands)
Operating revenues	$	243,060		$	42,934		$	119,916		$	(93	)	$	405,817
Intersegment revenues	—			9,635			—			(9,635		)	—
Total revenues	243,060			52,569			119,916			(9,728		)	405,817
Cost of energy	79,639			9,057			72,121			(9,636		)	151,181
Gross margin	163,421			43,512			47,795			(92		)	254,636
Other operating expenses	107,107			19,031			21,253			(3,805		)	143,586
Depreciation and amortization	22,924			10,040			210			4,202			37,376
Operating income (loss)	33,390			14,441			26,332			(489		)	73,674
Interest income	5,081			—			11			(9		)	5,083
Equity in net earnings (loss) of Optim Energy	—			—			—			(3,858		)	(3,858		)
Other income (deductions)	(1,991		)	283			(90		)	(1,546		)	(3,344		)
Net interest charges	(18,385		)	(7,953		)	(387		)	(5,036		)	(31,761		)
Segment earnings (loss) before income taxes	18,095			6,771			25,866			(10,938		)	39,794
Income taxes (benefit)	5,901			2,665			9,313			(4,387		)	13,492
Segment earnings (loss)	12,194			4,106			16,553			(6,551		)	26,302
Valencia non-controlling interest	(3,292		)	—			—			—			(3,292		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	8,770		$	4,106		$	16,553		$	(6,551	)	$	22,878

Six Months Ended June 30, 2010
Operating revenues	$	473,596		$	81,525		$	234,306		$	(215	)	$	789,212
Intersegment revenues	—			19,221			—			(19,221		)	—
Total revenues	473,596			100,746			234,306			(19,436		)	789,212
Cost of energy	166,073			18,107			177,111			(19,222		)	342,069
Gross margin	307,523			82,639			57,195			(214		)	447,143
Other operating expenses	215,900			37,822			41,701			(7,091		)	288,332
Depreciation and amortization	45,776			20,135			473			8,271			74,655
Operating income (loss)	45,847			24,682			15,021			(1,394		)	84,156
Interest income	10,015			—			13			82			10,110
Equity in net earnings (loss) of Optim Energy	—			—			—			(8,210		)	(8,210		)
Other income (deductions)	9,167			630			(98		)	(2,943		)	6,756
Net interest charges	(36,462		)	(15,822		)	(697		)	(10,190		)	(63,171		)
Segment earnings (loss) before income taxes	28,567			9,490			14,239			(22,655		)	29,641
Income taxes (benefit)	8,822			3,740			5,139			(9,149		)	8,552
Segment earnings (loss)	19,745			5,750			9,100			(13,506		)	21,089
Valencia non-controlling interest	(6,396		)	—			—			—			(6,396		)
Subsidiary preferred stock dividends	(264		)	—			—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	13,085		$	5,750		$	9,100		$	(13,506	)	$	14,429
At June 30, 2010:
Total Assets	$	3,813,524		$	1,013,131		$	239,035		$	337,832		$	5,403,522
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310

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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)


(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 wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the requirements of 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 retail load requirements were to be greater than anticipated. If all or a portion of retail 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 is 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 are negotiated with each customer. First Choice buys wholesale power in the competitive ERCOT wholesale market and sells power to retail customers in the competitive ERCOT retail market. Many of these retail customers buy power from First Choice for a contracted period of time at a fixed price so First Choice is exposed to price risk if the wholesale power price changes during the time of the contract. First Choice’s strategy is 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 vary significantly from forecasts (for example, due to extreme weather, other significant load changes or contract breaches), First Choice could have 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 June 30, 2011, after-tax losses

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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)

of less than $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 June 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 June 30, 2011 and December 31, 2010, amounts recognized for the legal right to reclaim cash collateral were $4.6 million and $3.4 million for PNMR and $2.6 million and $3.0 million for PNM. In addition, at June 30, 2011 and December 31, 2010, amounts posted as cash collateral under margin arrangements were $26.7 million and $32.0 million for PNMR and $1.4 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 June 30, 2011 and December 31, 2010.

Commodity Derivatives

Commodity derivative instruments are summarized as follows:



	PNMR						PNM
	Economic Hedges						Economic Hedges
	June 30, 2011			December 31, 2010			June 30, 2011			December 31, 2010
	(In thousands)
Current assets	$	18,840		$	15,999		$	935		$	1,443
Deferred charges	7,754			5,264			5			—
	26,594			21,263			940			1,443
Current liabilities	(27,285		)	(31,407		)	(1,720		)	(3,110		)
Long-term liabilities	(13,770		)	(12,831		)	(1,841		)	(2,009		)
	(41,055		)	(44,238		)	(3,561		)	(5,119		)
Net	$	(14,461	)	$	(22,975	)	$	(2,621	)	$	(3,676	)

The Company had no trading or designated cash flow hedge transactions at June 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 $0.3 million of current assets and $0.1 million of current liabilities at June 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

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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)

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
	June 30,						June 30,					June 30,
	2011			2010			2011		2010			2011			2010
Three Months Ended	(In thousands)
PNMR
Electric operating revenues	$	190		$	(121	)	$	—	$	(36	)	$	—		$	6,539
Cost of energy	(4,594		)	2,720			—		—			(318		)	(771		)
Total gain (loss)	$	(4,404	)	$	2,599		$	—	$	(36	)	$	(318	)	$	5,768
Recognized in OCI												$	318		$	(5,581	)
PNM
Electric operating revenues	$	190		$	(121	)	$	—	$	—		$	—		$	6,539
Cost of energy	(284		)	(37		)	—		—			—			(41		)
Total gain (loss)	$	(94	)	$	(158	)	$	—	$	—		$	—		$	6,498
Recognized in OCI												$	—		$	(6,311	)
Six Months Ended
PNMR
Electric operating revenues	$	1,334		$	(2,007	)	$	—	$	(33	)	$	—		$	13,288
Cost of energy	86			(29,229		)	—		—			(249		)	(1,246		)
Total gain (loss)	$	1,420		$	(31,236	)	$	—	$	(33	)	$	(249	)	$	12,042
Recognized in OCI												$	249		$	(4,818	)
PNM
Electric operating revenues	$	1,334		$	(2,007	)	$	—	$	—		$	—		$	13,288
Cost of energy	159			(3,662		)	—		—			—			14
Total gain (loss)	$	1,493		$	(5,669	)	$	—	$	—		$	—		$	13,302
Recognized in OCI												$	—		$	(6,078	)

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
June 30, 2011
PNMR	21,657,500	3,646,080
PNM	1,810,000	(1,237,793	)
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

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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)

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)
June 30, 2011
PNMR	$	9,543	$	2,580	$	1,675
PNM	$	3,047	$	2,580	$	370
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.

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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)



	June 30, 2011				December 31, 2010
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Equity securities:
Domestic value	$	2,525	$	27,986	$	5,108	$	25,491
Domestic growth	19,453		56,245		17,239		48,237
Multinational	405		14,089		2,730		10,670
Fixed income securities:
Municipals	1,630		38,884		837		37,595
U.S. Government	490		21,390		348		21,541
Corporate and other	606		9,195		573		8,402
Cash and equivalents	—		724		—		4,986
	$	25,109	$	168,513	$	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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
				(In thousands)
Proceeds from sales	$	46,770		$	15,586		$	94,890		$	36,285
Gross realized gains	$	8,700		$	1,526		$	13,490		$	3,431
Gross realized (losses)	$	(554	)	$	(510	)	$	(2,282	)	$	(1,872	)

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, except for the PVNGS lessor notes shown below. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings.

At June 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	$	1,988	$	—	$	—
After 1 year through 5 years	20,208		139,108		128,034
After 5 years through 10 years	10,784		3,262		—
Over 10 years	36,489		—		—
	$	69,469	$	142,370	$	128,034

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



	June 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
PNMR
Long-term debt	$	1,566,168	$	1,722,785	$	1,565,847	$	1,659,674
Investment in PVNGS lessor notes	$	124,527	$	124,311	$	136,145	$	141,663
Other investments	$	15,645	$	20,766	$	18,791	$	21,675
PNM
Long-term debt	$	1,055,756	$	1,079,797	$	1,055,748	$	1,056,864
Investment in PVNGS lessor notes	$	124,527	$	124,311	$	136,145	$	141,663
Other investments	$	4,118	$	4,432	$	5,068	$	5,563
TNMP
Long-term debt	$	310,650	$	417,378	$	310,337	$	385,220
Other investments	$	268	$	268	$	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:

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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)



				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total⁽¹⁾			(Level 1)			(Level 2)			(Level 3)
June 30, 2011				(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	724		$	724		$	—		$	—
Equity securities:
Domestic value	27,986			27,986			—			—
Domestic growth	56,245			56,245			—			—
Multinational	14,089			14,089			—			—
Fixed income securities:
U.S. government	21,390			16,797			4,593			—
Municipals	38,884			—			38,884			—
Corporate and other	9,195			—			9,195			—
Total NDT investments	$	168,513		$	115,841		$	52,672		$	—
PNMR
Commodity derivative assets	$	26,594		$	10,891		$	9,908		$	5,282
Commodity derivative liabilities	(41,055		)	(25,360		)	(14,292		)	(890		)
Net	$	(14,461	)	$	(14,469	)	$	(4,384	)	$	4,392
PNM
Commodity derivative assets	$	940		$	—		$	940		$	—
Commodity derivative liabilities	(3,561		)	—			(3,561		)	—
Net	$	(2,621	)	$	—		$	(2,621	)	$	—

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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)



				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 $0.5 million for PNMR and zero for PNM at June 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 six months ended June 30, 2011 and 2010.

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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)

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



	PNMR						PNM
	June 30,						June 30,
	2011			2010			2011		2010
Three Months Ended	(In thousands)
Balance at beginning of period	$	894		$	85		$	—	$	—
Total gains (losses) included in earnings	3,676			(437		)	—		—
Purchases	2,617			—			—		—
Settlements	(2,795		)	74			—		—
Balance at end of period	$	4,392		$	(278	)	$	—	$	—
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	$	1,954		$	(363	)	$	—	$	—
Six Months Ended
Balance at beginning of period	$	(822	)	$	248		$	—	$	(17	)
Total gains (losses) included in earnings	5,226			(814		)	—		(128		)
Purchases	2,735			—			—		—
Settlements	(2,747		)	288			—		145
Balance at end of period	$	4,392		$	(278	)	$	—	$	—
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	$	3,122		$	(543	)	$	—	$	—

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:

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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)



	PNMR					PNM
	June 30,					June 30,
	2011		2010			2011		2010
Three Months Ended	(In thousands)
Gains (losses) included in earnings:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	3,676		(437		)	—		—
Total	$	3,676	$	(437	)	$	—	$	—
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	1,954		(363		)	—		—
Total	$	1,954	$	(363	)	$	—	$	—
Six Months Ended
Gains (losses) included in earnings:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	5,226		(814		)	—		(128		)
Total	$	5,226	$	(814	)	$	—	$	(128	)
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	3,122		(543		)	—		—
Total	$	3,122	$	(543	)	$	—	$	—


(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				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	4,067	$	22,878	$	20,704	$	14,429
Average Number of Common Shares:
Outstanding during period	86,673		86,673		86,673		86,673
Equivalents from convertible preferred stock (Note 7)	4,778		4,778		4,778		4,778
Vested awards of restricted stock	139		109		149		102
Average Shares - Basic	91,590		91,560		91,600		91,553
Dilutive Effect of Common Stock Equivalents ⁽¹⁾:
Stock options and restricted stock	546		273		502		141
Average Shares - Diluted	92,136		91,833		92,102		91,694
Net Earnings Per Share of Common Stock:
Basic	$	0.04	$	0.25	$	0.23	$	0.16
Diluted	$	0.04	$	0.25	$	0.22	$	0.16


(1)	Excludes the effect of out-of-the-money options for 1,978,010 shares of common stock at June 30, 2011.

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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)


(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 six months ended June 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	(199,683	)	$	11.01
Forfeited	(8,333	)	$	11.33
Expired	(47,936	)	$	24.51
Outstanding at end of period	3,692,310		$	18.66	$	9,793,593	⁽¹⁾	5.36 years
Exercisable at end of period	3,152,000		$	21.86	$	6,663,441		4.85 years
Options available for future grant⁽²⁾	4,763,254

(1) At June 30, 2011, the exercise price of 1,978,010 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:



	Six Months Ended June 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)	$	2,199	$	329

Restricted Stock and Performance Shares

The following table summarizes nonvested restricted stock activity for the six months ended June 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	(110,757	)	$	9.69
Forfeited	—		$	—
Nonvested at end of period	435,249		$	11.91

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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)

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:



	Six Months Ended
	June 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)	$	1,073		$	1,308
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

At June 30, 2011, PNMR and PNM had revolving credit facilities with financing capacities of $542.0 million under the PNMR Facility and $386.0 million under the PNM Facility that primarily expire in August 2012. The financing capacities of the PNMR Facility and the PNM Facility will reduce by $25.0 million and $18.0 million in August 2011 according to their terms. The Company does not believe the scheduled reduction in the facilities will have a significant impact on PNMR’s and PNM’s liquidity. In addition, PNMR 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 June 30, 2011, the weighted average interest rate was 1.44% for the PNMR Facility and 0.84% for the PNM Facility. Short-term debt outstanding consists of:



	June 30,		December 31,
Short-term Debt	2011		2010
	(In thousands)
PNM – Revolving credit facility	$	273,000	$	190,000
TNMP – Revolving credit facility	—		—
PNMR
Revolving credit facility	31,000		32,000
Local lines of credit	—		—
	$	304,000	$	222,000

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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)

At August 2, 2011, PNMR, PNM, and TNMP had $455.1 million, $58.8 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 August 2, 2011, on a consolidated basis, was $588.6 million for PNMR. At August 2, 2011, PNMR and PNM had invested cash of $10.3 million and $10.7 million. TNMP had no such investments.

As of June 30, 2011, TNMP had outstanding borrowings of $7.0 million from PNMR under its intercompany loan agreement. At August 2, 2011, TNMP had outstanding borrowings of $5.0 million under its intercompany loan agreement with PNMR.

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 is accounted for as a cash-flow hedge and the June 30, 2011 pre-tax fair value of $2.1 million is included in other current liabilities, except for $1.0 million included in other deferred credits, and in AOCI on the Condensed Consolidated Balance Sheets. The hedge’s December 31, 2010 pre-tax fair value of $1.9 million is 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.

Convertible Preferred Stock

In November 2008, PNMR issued 477,800 shares of Series A convertible preferred stock. The Series A convertible preferred stock is convertible into PNMR common stock at a ratio of 10 shares of common stock for each share of preferred stock. The Series A convertible preferred stock is 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 Series A convertible preferred stock is 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 receive a preference of $0.10 per common share equivalent. After that preference, common holders would receive an equivalent liquidation preference per share and all remaining distributions would be shared ratably between common and preferred holders using the number of shares of common stock into which the Series A convertible preferred stock is convertible. The terms of the Series A convertible preferred stock result in it being substantially equivalent to common stock. Therefore, for earnings per share purposes the number of common shares into which the Series A convertible preferred stock is convertible is included in the weighted average number of common shares outstanding. Similarly, dividends on the Series A convertible preferred stock are 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.

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PNM Plans

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



	Three Months Ended June 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



	Six Months Ended June 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	$	—		$	—		$	129		$	210		$	—	$	—
Interest cost	16,402			17,037			2,689			3,825			465		527
Long-term return on plan assets	(18,537		)	(18,677		)	(2,694		)	(2,786		)	—		—
Amortization of net loss	4,605			3,225			1,603			2,744			47		35
Amortization of prior service cost	158			158			(1,324		)	(2,071		)	—		—
Net periodic benefit cost	$	2,628		$	1,743		$	403		$	1,922		$	512	$	562

PNM made contributions to its pension plan trust of $7.5 million and $13.5 million in the three months and six months ended June 30, 2011 and zero and $6.5 million in the three months and six months ended June 30, 2010. PNM anticipates making $28.0 million of additional contributions in 2011. Based on current law and estimates of portfolio performance, PNM estimates making contributions to its pension plan trust that total $190.0 million for 2012- 2015. The estimated contributions were developed using probabilistically determined 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 $1.2 million to the trust for other postretirement benefits for the three months and six months ended June 30, 2011 and $1.2 million for the three months and six months ended June 30, 2010. PNM expects to make contributions totaling $2.5 million 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 $0.4 million and $0.8 million in the three months and six months ended June 30, 2011 and $0.4 million and $0.7 million in the three months and six months ended June 30, 2010 and are expected to total $1.5 million during 2011.

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(Unaudited)

TNMP Plans

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



	Three Months Ended June 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



	Six Months Ended June 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	$	—		$	—		$	153		$	144		$	—	$	—
Interest cost	1,900			2,063			327			356			23		26
Long-term return on plan assets	(2,735		)	(2,897		)	(267		)	(257		)	—		—
Amortization of net (gain) loss	173			—			(96		)	(98		)	—		(2		)
Amortization of prior service cost	—			—			30			30			—		—
Net Periodic Benefit Cost (Income)	$	(662	)	$	(834	)	$	147		$	175		$	23	$	24

TNMP made contributions to its pension plan trust of $0.1 million and $0.2 million in the three months and six months ended June 30, 2011 and no contributions in the three months and six months ended June 30, 2010. TNMP anticipates making additional contributions of $1.0 million in 2011. Based on current law and estimates of portfolio performance, TNMP estimates making contributions to its pension plan trust that total $6.5 million for 2012-2015. The estimated contributions were developed using probabilistically determined 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 $0.4 million to the trust for other postretirement benefits for the three months and six months ended June 30, 2011 and $0.6 million for the three months and six months ended June 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 six months ended June 30, 2011 and 2010 and are expected to total $0.1 million during 2011.

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(Unaudited)

(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 results of operations or financial position. 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 adverse 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 established appropriate reserves 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 June 30, 2011 and December 31, 2010, PNM recorded interim storage costs of $15.1 million and $14.8 million in other deferred credits.

The Clean Air Act

Regional Haze

The 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 SO₂reduction milestones are not met.

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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. Using the 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.

PNM recently contracted with an independent engineering design firm to prepare a detailed conceptual design and cost estimate for installation of SCR at SJGS. That analysis utilized scaled vendor estimates and was submitted to the EPA on July 20, 2011. Although there are certain differences between the two analyses, the new 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, the 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 prohibit emissions from adversely affecting air quality in other states. EPA Region 6 issued a proposed interstate transport FIP, which was published in the Federal Register on January 5, 2011. The proposed FIP included a 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 the 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 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 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 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 would require 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 the EPA on June 24, 2011.

PNM filed extensive technical and legal comments on the proposed FIP with the EPA, including a statement in support of the then-draft SIP. Since the EIB had approved a SIP, PNM believed that the EPA must consider that SIP. 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 had 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. On August 5, 2011, the EPA issued its final FIP which requires SCR technology and allows for a five-year implementation schedule. The final FIP provides for an emission limit for NOx at SJGS of 0.05 pounds per MMBTU. PNM will file an appeal with the United States Court of Appeals for the Tenth Circuit within the required time frame, which is within 60 days after the final FIP is published in the Federal Register. The appeal would not stop the implementation timeframe unless a court issues a stay. 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 toward visibility

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improvements required under the EPA rules. The EPA indicated on August 5, 2011, that it would continue to review the state's SIP but that the EPA had already evaluated SNCR as part of the FIP and had ruled SNCR out as BART for San Juan.

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 approximately $85 for the first year with slowly declining costs for an estimated 20 years and that costs to businesses would be higher.

On January 19, 2011, multiple parties filed with the EPA a NOI to sue under the Clean Air Act for the 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 Clean Air Act 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 that requirements 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 the EPA concluding that certain combustion control equipment constitutes BART for Four Corners. Based on the analyses and comments received through EPA's rulemaking process, the EPA will determine what it believes constitutes BART for Four Corners.

On October 6, 2010, the 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's 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. The 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 under Coal Supply below 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 the EPA proposing an alternative to the 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 the 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 Clean Air Act.

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On February 10, 2011, the EPA signed a Supplemental Notice Requesting Comment, related to the BART rulemaking for Four Corners. In the Supplemental Notice, the EPA proposed to find that a different alternative emission control strategy, based upon APS's November 2010 proposal, would achieve more progress than the 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 the EPA in October 2010. The 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 the EPA has failed to fulfill its nondiscretionary duty under the Clean Air Act to submit a BART determination for the plants without unreasonable delay. The Clean Air Act requires parties to give EPA 180 days' notice before commencing a lawsuit based on allegations that the 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 the 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, the 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 the 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 the 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. 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 the EPA that San Juan County be designated as non-attainment. On January 6, 2010, the 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”). The EPA had intended to establish a new ozone standard by July 31, 2011, but has delayed the announcement of its rule. Depending upon where the standard is set, 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 as early as 2014. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. A non-attainment designation for Bernalillo County could result in the requirement to reduce NOxemissions from Reeves Station as early as 2014. The Company 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

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quarter. As required by the Consent Decree, PNM submitted reports addressing mercury and NOx emission controls for SJGS. 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 operating costs for the entire station by as much as $42 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. 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 Clean Air Act. 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 the EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners. This request is part of an enforcement initiative that the EPA has undertaken under the Clean Air Act. The 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 Clean Air Act. 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 the EPA. APS has responded to the 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 Notice of Intent to Sue

On May 7, 2010, APS received a NOI to sue from Earthjustice, on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at Four Corners. The NOI alleges NSR related violations and NSPS violations. Under the Clean Air Act, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit. Within that 60-day time period, the EPA may step in and file a lawsuit regarding the allegations. If the EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in the EPA's lawsuit, if it so desires. The 60-day period lapsed in July 2010, and the EPA did not take any action. At this time, the Company cannot predict whether or when Earthjustice might file a lawsuit or, if filed, what the ultimate outcome would be.

Review of New Sources and Modifications in Indian Country

Pursuant to its authority under the Clean Air Act, in June 2011, the 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

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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

The 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 has been extended to August 18, 2011. The 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 the EPA, which states that neither the source nor extent of contamination has been determined and also states that the source

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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 the EPA and the New Mexico State Engineer's Office.

On May 4, 2010, the 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 the 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 the 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. The 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 the 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, the 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 the 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 the 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 the 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 the EPA's or OSM's proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material adverse 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

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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, the 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. The 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 had no material adverse impact on PNM's financial position, results of operations, or cash flows.

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 June 30, 2011 and December 31, 2010, prepayments for coal, which are included in other current assets, amounted to $28.2 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 June 30, 2011, are estimated to be $54.5 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 $2.6 million during the three and six months ended June 30, 2011 and $0.9 million and $2.0 million during the three and six months ended June 30, 2010. As of June 30, 2011 and December 31, 2010, obligations of $24.2 million and $25.0 million for surface mine reclamation and $2.9 million and $2.8 million for underground mining activities were recorded in other deferred credits.

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.

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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 the 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 adverse 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

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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 has set a deadline of September 16, 2011 for interested parties to file a NOI to participate, and a mandatory scheduling conference has been set for October 3, 2011.

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 other claimants and potential claimants. 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.

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.

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On May 10, 2010, Plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs. PNM intends to participate in order to preserve its interests regarding any PNM-acquired rights-of-way implicated in the appeal. As the administrative appeal process is in its initial stages, PNM cannot predict the outcome of the proceeding at this time or the range of potential outcomes.

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 continues to evaluate its transmission system under the provisions of the two Reliability Standards and consult with other transmission facility owners with whom PNM is interconnected to determine the impact on the capability of its 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 that have selected the MOD-029-1 methodology that, while they were still expected to be compliant with the standard on April 1, 2011, NERC has delayed the implementation for "Flow Limited" paths only, 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.

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

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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. If the stipulation in the 2010 Electric Rate Case discussed below is 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 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 7 MW of solar PV were in service at June 30, 2011, and PNM anticipates that all 22 MW 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. The NMPRC granted rehearing on July 14, 2011 and took under advisement the issues raised in the rehearing motions. PNM cannot predict the outcome of this matter.

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On April 6, 2011, PNM issued a RFP for renewable energy and RECs of up to 360,000 MWh annually. Proposals were due on June 10, 2011 and PNM is currently analyzing the proposals received. PNM will use these proposals to develop its plan for compliance with the RPS in 2012-2014.

On July 1, 2011, PNM filed its Renewable Energy Portfolio Procurement Plan for 2012. The plan requests approval of a proposed portfolio and the costs that would be incurred under that portfolio of approximately $20.3 million in 2012. The proposed portfolio consists of existing resources and proposes three new procurements. 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 new 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 does not request approval of them since they would exceed the RCT. PNM cannot predict the outcome of this matter.

NMPRC Rulemaking on Disincentives 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 allows electric 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 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 stipulation in the 2010 Electric Rate Case, PNM agreed that any such disincentives would be deemed addressed under the new rates proposed in the stipulation. Under the amended rule, after such measures become effective, the rate adder for energy saving is reduced to $0.005 per KWh. The NMAG and NMIEC appealed the NMPRC order adopting the amended rule to the New Mexico Supreme Court and subsequently moved the court for a stay of the NMPRC order, which was denied. The New Mexico Supreme Court issued an opinion on July 27, 2011 annulling and vacating the NMPRC's final order approving the rule amendments and remanded the matter to the NMPRC for further action in accordance with the opinion. The appellees have until August 11, 2011 to request rehearing. PNM cannot predict the ultimate outcome of this matter.

On May 5, 2010, PNM filed proposed tariffs under the amended rule to recover a rate 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. A public hearing was held on September 14, 2010 and the NMPRC issued an order on November 29, 2010 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 to 18 months. If the opinion issued by the Supreme Court on July 27, 2011 is not reheard and changed, PNM will be precluded from continuing this rate rider. Of the $4.2 million authorized for recovery, $1.9 million had been collected as of June 30, 2011.

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 programs adder discussed above. Based on testimony filed by other parties, PNM accepted certain modifications to the plan the effect of which was a revised proposed recovery amount of $31.4 million. A public hearing was held in February 2011. The NMPRC issued a final order on June 23, 2011 that rejected the plan modifications proposed by PNM 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 also 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

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Report. The final order approved a rider recovery amount of $22.8 million, including adder revenues of $5.7 million. The adder revenues include $1.9 million of 2010 efficiency programs discussed above that will not have been 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 and PNM anticipates making a further reduction in the rider rate resulting from the Supreme Court decision in the disincentive rulemaking discussed above.

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 requesting additional information from PNM concerning program costs, the NMPRC suspended the proposed adjusted rates for 180 days commencing on May 1, 2011. The NMPRC concluded that some of the program costs exceeded approved budgets and determined that an evidentiary hearing should be held to consider PNM's recovery of 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 agreement on issues raised by the reconciliation filing and the NMPRC's suspension order. Under the agreement 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 have filed testimony supporting the settlement. No party has filed testimony in opposition. In a hearing held in July 2011, although no party raised the issue, the Hearing Examiner questioned the reconciliation of 2009 Energy Efficiency Plan costs. He 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. Because the issue had not previously been raised, he gave PNM until August 4, 2011 to file contrary evidence. PNM's filing asserts that the cost overruns are not as great as the Hearing Examiner calculated, that the costs were incurred for the provision of cost-effective energy efficiency programs, and that they should be deemed approved. PNM is unable to predict the outcome of this matter.

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. PNM cannot predict the outcome of this matter.

2010 Electric Rate Case

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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. If the NMPRC were to grant the entire relief requested, PNM proposed to implement the increase in two steps. 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 is 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. On July 27, 2010, in response to motions filed by the NMPRC staff and other parties, the NMPRC determined that PNM's rate filing was incomplete, ordered PNM to supplement its rate application, directed that the suspension period not begin to run until PNM's rate application was made complete, and extended the suspension period by one month. PNM believed that the order was erroneous both in its assessment of the completeness of PNM's filing and in its application of the governing legal standards. On August 5, 2010, PNM supplemented its rate case application in conformance with the NMPRC's order and also petitioned the New Mexico Supreme Court requesting the Court to vacate the NMPRC's July 27, 2010 order and for other equitable relief. The Supreme Court denied PNM's petition on September 13, 2010. In October 2010, PNM began meeting with the NMPRC staff and other parties to discuss settlement. To accommodate these settlement discussions, the Hearing Examiner and the NMPRC issued orders revising the hearing schedule and extending the suspension period.

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 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 February 22, 2011, the NMPRC issued an order requiring PNM to agree to extend the suspension period for an additional three months from August 10, 2011 as a condition for going forward with hearings on the stipulation, in order to accommodate the procedural schedule that would be needed if the stipulation was not ultimately approved. PNM gave notice to the NMPRC on February 25, 2011 that it agreed to extend the suspension period until November 10, 2011. 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. Several parties filed testimony in opposition to the stipulation. 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 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. As discussed in Note 16, on August 8, 2011, the NMPRC issued a final order that provides for a $72.1 million rate increase and adopts, approves, and accepts the stipulation with other modifications.

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. Unless a protest demonstrating the need

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for a hearing is filed within 30 days of that date, the NMPRC is authorized to accept the plan without a hearing. If the NMPRC does not act on the IRP within 45 days after the filing of the IRP, the IRP is deemed accepted as compliant with the rules. 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. 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. TNMP is unable to predict the ultimate outcome of 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 27, 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 decision of the Texas 3^rd Court of Appeals, TNMP is no longer able to assert that it will ultimately be successful in overturning any ruling that the effective date should be prior to December 27, 2007. Accordingly, 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. The final order will permit TNMP to begin collection of a surcharge on August 11, 2011 in order to collect

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a total of $113.3 million in costs over 12 years.

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, allowing TNMP to collect $2.8 million over three years beginning 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. TNMP cannot predict the potential range of outcomes or 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.

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 are due on August 8, 2011 with reply comments due on August 12, 2011. If requested, a public hearing may be held on August 15, 2011.

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(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 have a 50 percent ownership interest in Optim Energy, a limited liability company.

Impairment Considerations

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. 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) has been assessing various strategic alternatives relating to PNMR’s ownership interest in Optim Energy. PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources and, as of the date of this report, PNMR does not anticipate making additional contributions to Optim Energy. The strategic alternative process is ongoing and no decisions have been reached.

Operational Information

Optim Energy has a bank financing arrangement that expires on May 31, 2012, which includes a revolving line of credit. This facility also provides for bank letters of credit to be issued as credit support for certain contractual arrangements entered into by Optim Energy. Cascade and ECJV have guaranteed Optim Energy’s obligations on this facility and, to secure Optim Energy’s obligation to reimburse Cascade and ECJV for any payments made under the guaranty, have a first lien on all assets of Optim Energy and its subsidiaries.

In January 2010, Optim Energy entered into one-year floating-to-fixed interest rate swaps with an aggregate notional amount of $650.0 million. The effect of these swaps was to convert $650.0 million of borrowings under Optim Energy’s credit facility from an interest rate based on the one-month LIBOR rate to a fixed rate of 1.33% through January 7, 2011, exclusive of loan guaranty fees. These swaps were accounted for as cash-flow hedges.

PNMR has no commitments or guarantees with respect to Optim Energy.

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Summarized financial information for Optim Energy is as follows:

Results of Operations



	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
				(In thousands)
Operating revenues	$	77,315		$	86,871		$	151,248		$	192,465
Cost of energy	54,908			61,235			112,875			138,532
Gross margin	22,407			25,636			38,373			53,933
Non-fuel operations and maintenance expenses	9,408			6,450			18,651			16,970
Administrative and general expenses	6,356			4,944			13,293			10,556
Depreciation and amortization expense	13,126			12,852			24,739			24,909
Taxes other than income tax	2,347			3,162			4,717			6,596
Operating income (loss)	(8,830		)	(1,772		)	(23,027		)	(5,098		)
Interest charges	(3,981		)	(4,661		)	(7,965		)	(9,332		)
Other income (deductions)	195			2			263			66
Earnings (loss) before income taxes	(12,616		)	(6,431		)	(30,729		)	(14,364		)
Income taxes⁽¹⁾	94			36			141			68
Net earnings (loss)	$	(12,710	)	$	(6,467	)	$	(30,870	)	$	(14,432	)
50 percent of net earnings (loss)	$	(6,355	)	$	(3,234	)	$	(15,435	)	$	(7,216	)
Amortization of basis difference in Optim Energy	—			(624		)	—			(994		)
Post-impairment loss not recorded under GAAP	6,355			—			15,435			—
PNMR equity in net earnings (loss) of Optim Energy	$	—		$	(3,858	)	$	—		$	(8,210	)

⁽¹⁾ Represents the Texas Margin Tax, which is considered an income tax under GAAP.

Financial Position



	June 30,			December 31,
	2011			2010
	(In thousands)
Current assets	$	102,851		$	105,413
Net property plant and equipment	908,666			924,354
Other long-term assets	112,196			120,894
Total assets	1,123,713			1,150,661
Current maturities of long-term debt	717,000			—
Other current liabilities	52,220			50,226
Long-term debt	—			717,000
Other long-term liabilities	9,397			7,515
Total liabilities	778,617			774,741
Owners’ equity	$	345,096		$	375,920
50 percent of owners’ equity	$	172,548		$	187,960
PNMR basis difference in Optim Energy	193			216
Impairment of equity investment in Optim Energy	(188,176		)	(188,176		)
Post-impairment loss not recorded under GAAP	15,435			—
PNMR equity investment in Optim Energy	$	—		$	—

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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)

Revenue related to power sales and purchases is included net in operating revenues. Costs related to fuel purchases and sales are recorded net in cost of energy.

PNMR had a basis difference between its recorded investment in Optim Energy and 50 percent of Optim Energy’s equity resulting from Optim Energy’s acquisition of the Twin Oaks plant from PNMR in 2007. The portion of the basis difference related to contract amortization ended in 2010 and other basis differences, including a difference related to emission allowances that would have continued through the life of the Twin Oaks plant, were taken into account in the impairment discussed above. The basis difference adjustment detailed above relates mainly to contract amortization with insignificant offsets related to the other minor basis difference components.

Optim Energy individually valued each asset and liability of the Twin Oaks plant acquired from PNMR and the acquisition of Cogen and initially recorded them on its balance sheet at the determined fair value. For both transactions, this accounting resulted in amortization since contracts acquired were out of market and emission allowances, while acquired from government programs without cost to Optim Energy, had market value. Optim Energy recorded amortization of contracts acquired of $3.7 million and $7.3 million for the three months and six months ended June 30, 2011 and $4.2 million and $8.2 million for the three months and six months ended June 30, 2010, which decreased operating revenues. Optim Energy also recorded amortization expense on emission allowances of $1.6 million and $4.1 million for the three months and six months ended June 30, 2011 and $1.3 million and $2.6 million for the three months and six months ended June 30, 2010, which increased cost of energy.

(12) Related Party Transactions

PNMR, PNM, TNMP, and 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 is 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				Six Months ended
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands)
Electricity, transmission and distribution related services billings:
TNMP to PNMR	$	9,598	$	9,635	$	18,412	$	19,221
Services billings:
PNMR to PNM	24,733		21,913		46,169		43,575
PNMR to TNMP	7,374		5,804		13,955		12,292
PNM to TNMP	160		178		287		278
TNMP to PNMR	44		93		97		214
PNMR to Optim Energy	1,404		1,371		2,804		2,809
Optim Energy to PNMR	9		33		19		51
Income tax sharing payments:
PNMR to PNM	—		35,190		—		35,190
Interest charges:
TNMP to PNMR	26		102		28		185
PNM to PNMR	8		—		36		—
PNMR to PNM	32		—		64		—

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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)

(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. PNM is currently evaluating the impacts of the license extensions.

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. Regardless of the approach elected, entities will be required to show the impacts of reclassification adjustments from other comprehensive income in both the statements of net income and the statements in which other comprehensive income is presented. 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.

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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 is considered to have an indefinite useful life; therefore, no amortization is 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) Subsequent Events

PNM's 2010 Electric Rate Case is discussed in Note 10. On August 8, 2011, a majority of the commissioners of the NMPRC signed a final order that adopts, approves, and accepts the stipulation in the 2010 Electric Rate Case with certain modifications. The order provides that, for the order to become effective, PNM and the other signers of the stipulation have until August 12, 2011 to formally accept the modifications or to indicate that they either do not oppose or take no position on the modifications. Therefore, no assurance can be given that the NMPRC's order will become effective. If the signers of the stipulation do not accept the modifications, any one of them could ask the NMPRC to rehear and reconsider the order, or specific aspects of it. Other parties could also request rehearing and reconsideration whether or not the modifications are opposed by any of the signers. PNM cannot predict if any party will request rehearing or the outcome of any such request. If the order does not become effective, PNM would proceed with litigation of the original case, which requested a $165.2 million rate increase, before the NMPRC.

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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 NMPRC's modifications include:


•	A revenue increase for PNM's New Mexico retail customers of $72.1 million that PNM could implement currently, thereby eliminating the phased-in increases contained in the stipulation;


•	Elimination of the rider that would have allowed PNM to increase rates in 2013 by up to $20.0 million based on changes in plant-related rate base between June 30, 2010 and December 31, 2012;


•	A change in rate design for the residential customer class;


•	If approved by the signers, a change in the moratorium on the next general increase in PNM's rates, such that the increase could not become effective before July 1, 2013, rather than January 1, 2014 as specified in the stipulation.

Provisions of the stipulation that the NMPRC did not alter include:


•	Allowing PNM to file for recovery of the costs of renewable energy procurement programs through a rate rider;


•	Allowing PNM to file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010;


•	The proposed convergence of rates for PNM North and PNM South;


•	The same FPPAC for PNM North and PNM South customers;


•	The agreement among the signers of the stipulation to seek dismissal of the NMPRC's proceeding concerning PNM's replacement power costs recovered through the FPPAC, which is discussed under Emergency FPPAC in Note 10;


•	PNM's agreement to forego $10.0 million of the under-collected amount in the FPPAC balancing account.

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 (Loss).

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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 unregulated markets to help customers meet and manage their energy needs.

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. 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. 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 20% increase for PNM South. 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 is the first rate case filing in New Mexico proposing a future test year consistent with recent amendments to the Public Utility Act. 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 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, which would be recorded as a regulatory disallowance. On February 22, 2011, the NMPRC issued an order requiring PNM to extend the suspension period for an additional three months to November 10, 2011. 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. Several parties filed testimony in opposition to the stipulation. A public hearing on the stipulation was held in May 2011. On June 21, 2011, the hearing examiner recommended approval of most of the terms of the stipulation, including the $85.0 million rate

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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. See Note 10. At the open meeting of the NMPRC on July 28, 2011, the NMPRC commissioners voted to issue an order that would modify the stipulation. As discussed in Note 16, on August 8, 2011, the NMPRC issued a final order that provides for a $72.1 million rate increase and adopts, approves, and accepts the stipulation with other modifications.

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

As noted above, PNM also serves customers in New Mexico formerly served by TNMP. When PNMR acquired TNMP, PNM was required to maintain the former TNMP customers under rates separate from the rest of PNM. Pursuant to a stipulation approved by the NMPRC, PNM was prohibited from consolidating the cost of service for the two areas until January 1, 2015, unless the consolidation would not result in shifting more than $1.5 million in revenue requirements from the former TNMP customers to other PNM customers. In addition, the stipulation provided that PNM would not seek rate changes for the former TNMP customers that would go into effect before January 1, 2011. During 2009, the NMPRC requested that the parties to the stipulation meet to discuss ways and means of mitigating possible large rate increases to the former TNMP customers that may occur when the rate moratorium expires. The parties met periodically under the direction of a NMPRC Hearing Examiner, who was appointed by the NMPRC to serve as mediator for the discussions, but did not reach agreement. The 2010 Electric Rate Case discussed above provides for a rate increase to the former TNMP customers . In April 2011, the NMPRC issued an order that consolidated this case with the 2010 Electric Rate Case. See Note 10 and Note 16.

TNMP

TNMP’s financial health is also highly dependent on continued favorable regulatory treatment. TNMP now has the ability to update its transmission rates twice a year to reflect changes in its invested capital. Additionally, on May 28, 2011, Texas Governor Perry signed a bill, which will allow for an annual periodic rate adjustment to reflect changes in invested distribution capital. A rule-making proceeding has been initiated by the PUCT to implement this new rule. 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 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. 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 will permit 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

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historically has operated through a series of geographic zones and congestion of the transmission system has occurred when large volumes of power were being transmitted between zones. Congestion tends to drive prices up in the spot market. These anomalies also negatively impacted the margins realized from end use customers. Beginning in 2008, these conditions were exacerbated by the impacts of Hurricane Ike and depressed economic conditions resulting in very high levels of customer turnover and levels of uncollectible accounts significantly higher than historical experience. ERCOT has made changes in its control protocols and changed from the zonal system to a nodal system in December 2010, both of which should reduce congestion and price volatility. Recently, the Texas retail market has been more stable and First Choice does not anticipate that extreme congestion and price volatility will reoccur in the near future. 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 have contributed to an improvement in First Choice’s results of operations, including reductions in bad debt expense. For 2011, First Choice expects market conditions to continue to be a key factor for the business and believes margins will continue to decline as they return to more historic levels. In September 2010, the PUCT adopted a “switch/hold” provision for customer accounts on a deferred payment plan, an average payment plan, or with a meter determined to have been tampered with, which will require those customers to pay any outstanding balance before changing to another REP. The switch/hold provision became effective on June 1, 2011, but its impact is unknown at this time.

Optim Energy

PNMR has previously reported that it intended to capitalize on growth opportunities in its unregulated business through its participation and ownership in Optim Energy. PNMR’s 50 percent ownership of Optim Energy allows it to participate in the operation of Optim Energy’s assets and business and the formulation of Optim Energy’s business strategy. Optim Energy owns electric generating assets in one of the nation’s growing power markets, and its strategy had been focused on acquiring or developing additional assets in that market. Optim Energy has a bank financing arrangement that expires on May 31, 2012, which includes a revolving line of credit.

In 2009, Optim Energy was affected by continuing adverse market conditions, primarily low natural gas and power prices. The adverse market conditions have continued throughout 2010 and 2011. In response to those adverse conditions, in October 2009, Optim Energy changed its strategy and near-term focus. Optim Energy is currently focused on utilizing cash flow from operations to reduce debt and optimizing its current generation assets as a stand-alone independent power producer. Optim Energy’s goal is to optimize its performance under current market conditions with the expectation of being able to take advantage of any economic recovery in the power and gas markets over the next several years.

In addition to the continuing adverse market conditions evidenced by low power and natural gas prices, 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 discussed in Note 11, PNMR performed an impairment analysis in accordance with GAAP of its investment in Optim Energy as of December 31, 2010. PNMR’s analysis of the discounted cash flows of Optim Energy, recent sales of comparable generating assets, and the preliminary assessments of strategic alternatives for Optim Energy (see Strategy below) indicated that its entire investment in Optim Energy was impaired at December 31, 2010. Accordingly, PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31, 2010. In accordance with GAAP, PNMR did not record 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.

Strategy

As a result of the adverse market conditions experienced by Optim Energy described above, PNMR (in collaboration with Optim Energy and ECJV) has been assessing various strategic alternatives relating to PNMR’s ownership interest in Optim Energy. PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources and, as of the date of this report, PNMR does not anticipate making additional contributions to Optim Energy.

Separately, PNMR is also evaluating strategic alternatives with respect to First Choice. Both of the strategic alternative processes are ongoing and no decisions have been reached.

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Environmental Sustainability

The Company’s focus on the electric businesses also includes 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 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. The tightening of the credit markets coupled with extreme volatility in commodity markets has had a direct, negative impact on several of First Choice’s competitors in the ERCOT retail market.

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 existing 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. The PNMR Facility and PNM Facility expire in 2012 and will need to be renegotiated or replaced in order to provide sufficient liquidity to finance operations and construction expenditures. The availability of such credit facilities and their terms and conditions will depend on the credit markets at that time, as well as the Company’s credit ratings and operating results. The Company is closely monitoring its liquidity and the credit markets. 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 June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
	(In millions, except per share amounts)
Net earnings	$	4.1	$	22.9	$	(18.8	)	$	20.7	$	14.4	$	6.3
Average common and common equivalent shares outstanding	92.1		91.8		0.3			92.1		91.7		0.4
Net earnings per diluted share	$	0.04	$	0.25	$	(0.21	)	$	0.22	$	0.16	$	0.06

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



	Three Months Ended			Six Months Ended
	June 30, 2011			June 30, 2011
	(In millions)
PNM Electric	$	(10.3	)	$	(11.0	)
TNMP Electric	—			2.5
First Choice	(10.0		)	11.0
Corporate and Other	(2.4		)	(4.4		)
Optim Energy	3.9			8.2
Net change	$	(18.8	)	$	6.3

Detailed information regarding the changes in earnings is included in the segment information below. The after-tax changes for the three months and six months ended June 30, 2011 relate primarily to the write off of regulatory disallowances of $10.6 million at PNM and $2.6 million at TNMP. In addition, unrealized mark-to-market gains were $0.9 million for the six months ended 2011 compared to unrealized losses of $3.4 million for the six months ended 2010 at PNM. For the three and six months ended June 30, 2011, TNMP revenues and margins increased associated with the implementation of a $10.25 million base rate increase beginning February 1, 2011 and a transmission rate increase in May 2010. At First Choice, losses on unrealized economic hedges decreased earnings by $2.3 million in 2011 compared with gains of $6.0 million in 2010. Mark-to-market gains on unrealized economic hedges at First Choice increased earnings by $3.6 million in the six months ended June 30, 2011 compared to a decrease in earnings of $11.9 million in 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 as PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources. 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 June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
							(In millions)
Total revenues	$	239.2		$	243.1		$	(3.8	)	$	473.5		$	473.6		$	(0.1	)
Cost of energy	81.5			79.6			2.0			170.7			166.1			4.6
Gross margin	157.7			163.4			(5.8		)	302.8			307.5			(4.7		)
Operating expenses	124.3			107.1			17.2			227.4			215.9			11.5
Depreciation and amortization	22.9			22.9			—			46.6			45.8			0.8
Operating income	10.5			33.4			(22.9		)	28.7			45.8			(17.1		)
Other income (deductions)	8.7			3.1			5.6			18.0			19.2			(1.2		)
Net interest charges	(18.0		)	(18.4		)	0.4			(36.1		)	(36.5		)	0.4
Earnings before income taxes	1.2			18.1			(16.9		)	10.6			28.6			(18.0		)
Income (taxes) benefit	0.9			(5.9		)	6.8			(1.5		)	(8.8		)	7.3
Valencia non-controlling interest	(3.5		)	(3.3		)	(0.2		)	(6.7		)	(6.4		)	(0.3		)
Preferred stock dividend requirements	(0.1		)	(0.1		)	—			(0.3		)	(0.3		)	—
Segment earnings (loss)	$	(1.5	)	$	8.8		$	(10.3	)	$	2.1		$	13.1		$	(11.0	)

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



	2011/2010 Change
	Three Months Ended June 30,								Six Months Ended June 30,
	Total			Cost of		Gross			Total			Cost of			Gross
	Revenues			Energy		Margin			Revenues			Energy			Margin
						(In millions)
Retail rate increases	$	—		$	—	$	—		$	3.1		$	—		$	3.1
Retail load, fuel, and transmission	6.0			1.1		4.9			12.5			7.2			5.3
Unregulated margins	(10.3		)	0.2		(10.5		)	(19.6		)	0.6			(20.2		)
Net unrealized economic hedges	0.5			0.7		(0.2		)	3.9			(3.2		)	7.1
Total increase (decrease)	$	(3.8	)	$	2.0	$	(5.8	)	$	(0.1	)	$	4.6		$	(4.7	)

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011		2010			Change
				(In millions, except customers)
Residential	$	78.5		$	79.2		$	(0.7	)	$	166.7	$	163.6		$	3.1
Commercial	95.1			91.7			3.4			172.0		164.6			7.4
Industrial	22.6			20.7			1.9			43.3		41.0			2.3
Public authority	5.6			5.0			0.6			10.4		9.4			1.0
Other retail	2.4			3.0			(0.6		)	4.5		4.9			(0.4		)
Transmission	10.9			9.1			1.8			21.0		18.9			2.1
Firm requirements wholesale	7.4			6.9			0.5			17.0		15.1			1.9
Other sales for resale	17.2			28.6			(11.4		)	37.8		59.2			(21.4		)
Mark-to-market activity	(0.5		)	(1.1		)	0.6			0.8		(3.1		)	3.9
	$	239.2		$	243.1		$	(3.8	)	$	473.5	$	473.6		$	(0.1	)
Average retail customers (thousands)	503.7			501.3			2.4			503.7		501.1			2.6

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2011	2010	Change		2011	2010	Change
			(Gigawatt hours)
Residential	729.4	744.3	(14.9	)	1,581.3	1,602.8	(21.5	)
Commercial	1,038.4	1,024.6	13.8		1,930.3	1,905.8	24.5
Industrial	397.1	363.9	33.2		758.4	713.7	44.7
Public authority	72.5	63.6	8.9		130.0	117.8	12.2
Firm requirements wholesale	143.0	163.1	(20.1	)	326.3	340.3	(14.0	)
Other sales for resale	518.7	544.2	(25.5	)	1,129.4	1,085.4	44.0
	2,899.1	2,903.7	(4.6	)	5,855.7	5,765.8	89.9

Unregulated revenues and margins from the activities 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. The increase in retail loads was driven largely by industrial customers, as well as 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.

Changes in unrealized mark-to-market gains and losses are based on economic hedges in place for fuel costs not covered under the FPPAC. Unrealized gains of $1.5 million for the six months ended 2011 compared to unrealized losses of $5.6 million for the six months ended 2010, increased gross margin by $7.1 million. Changes in unrealized mark-to-market gains and losses for the three months ended June 30, 2011 decreased gross margin by $0.2 million compared to 2010.

Operating expenses reflect reduced maintenance costs of $5.4 million and $9.3 million for the three and six months ended June 30, 2011 incurred at generation facilities, due primarily to timing of planned outages and improved performance at SJGS. For the six months ended June 30, 2011, maintenance costs were also reduced by $2.1 million due to timing of a major outage at Four Corners in the first quarter of 2010. Lower pension and benefits costs of $0.4 million and $0.7 million and reduced allocation of corporate costs of $0.6 million and $1.2 million further reduced operating expenses in the three and six months ended June 30, 2011. These reductions are partially offset by increases in expenses for recently renewed transmission rights-of-way agreements

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of $1.4 million and $2.9 million and higher property taxes of $0.6 million and $0.9 million due to increased investment in transmission and distribution assets. Operating expenses also 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 six months ended June 30, 2011, depreciation and amortization costs increased as a result of higher depreciable plant amounts, primarily associated with transmission and distribution assets. In the second quarter of 2011, PNM reduced the accretion expense associated with its ARO for decommissioning of PVNGS, which lowered depreciation and amortization expense for the second quarter. The reduction to accretion expense was driven by a decrease in the expected cash flows for the final decommissioning of PVNGS. The updated cash flows include a reduction in the inflation rate used to determine the future value of the costs and incorporate a decommissioning study updated in 2010, which reflects a 20 year life extension for each of the three units at PVNGS due to operating license extensions granted by the NRC.

For the three and six months ended June 30, 2011, increases in realized gains on the NDT assets improved other income by $6.7 million and $10.8 million, which was partially offset by $0.7 million and $1.7 million lower capitalization of the equity portion of allowance for funds used during construction ("AFUDC"), and $0.8 million and $1.6 million in lower interest income on the PVNGS lessor notes due to a lower outstanding balance. For the six months ended June 30, 2011, other income is lower due to an $8.5 million settlement associated with the Republic Savings Bank litigation received in the first quarter of 2010.

Lower interest rates on debt refinancing in the second quarter of 2010 reduced interest charges for the three and six months ended June 30, 2011. These savings 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 June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
							(In millions)
Total revenues	$	60.0		$	52.6		$	7.4		$	113.8		$	100.7		$	13.1
Cost of energy	10.3			9.1			1.2			20.4			18.1			2.3
Gross margin	49.7			43.5			6.2			93.4			82.6			10.8
Operating expenses	25.3			19.0			6.3			45.0			37.8			7.2
Depreciation and amortization	10.7			10.0			0.7			21.0			20.1			0.9
Operating income	13.7			14.4			(0.7		)	27.4			24.7			2.7
Other income (deductions)	0.3			0.3			—			0.6			0.6			—
Net interest charges	(7.3		)	(8.0		)	0.7			(14.6		)	(15.8		)	1.2
Earnings before income taxes	6.6			6.8			(0.2		)	13.4			9.5			3.9
Income (taxes)	(2.5		)	(2.7		)	0.2			(5.1		)	(3.7		)	(1.4		)
Segment earnings	$	4.1		$	4.1		$	—		$	8.3		$	5.8		$	2.5

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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 June 30,						Six Months Ended June 30,
	Total		Cost of		Gross		Total		Cost of		Gross
	Revenues		Energy		Margin		Revenues		Energy		Margin
					(In millions)
Rate increases	$	2.3	$	—	$	2.3	$	5.0	$	—	$	5.0
Customer usage/load	2.2		—		2.2		2.8		—		2.8
Transmission cost recovery	2.6		1.2		1.4		4.6		2.3		2.3
Other	0.3		—		0.3		0.7		—		0.7
Total increase	$	7.4	$	1.2	$	6.2	$	13.1	$	2.3	$	10.8

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



	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
			(In millions, except consumers)
Residential	$	23.8	$	20.1	$	3.7		$	43.3	$	39.0	$	4.3
Commercial	20.9		19.7		1.2			40.3		37.2		3.1
Industrial	3.0		3.1		(0.1		)	6.2		6.0		0.2
Other	12.3		9.7		2.6			24.0		18.5		5.5
	$	60.0	$	52.6	$	7.4		$	113.8	$	100.7	$	13.1
Average consumers (thousands) ⁽¹⁾	231.3		229.4		1.9			230.9		229.0		1.9

(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 67,268 and 76,768 consumers for the three months ended June 30, 2011 and 2010, and 68,187 and 77,981 for the six months ended June 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 June 30,			Six Months Ended June 30,
	2011	2010	Change	2011	2010	Change
			(Gigawatt hours⁽¹⁾)
Residential	722.0	643.7	78.3	1,304.3	1,255.2	49.1
Commercial	615.4	588.5	26.9	1,122.0	1,064.9	57.1
Industrial	635.4	577.0	58.4	1,255.9	1,093.8	162.1
Other	28.3	25.8	2.5	53.9	50.6	3.3
	2,001.1	1,835.0	166.1	3,736.1	3,464.5	271.6


(1)	The GWh sales reported above include 241.6 and 246.9 GWhs for the three months ended June 30, 2011 and 2010, and 451.2 and 496.4 GWhs for the six months ended June 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.

For the three and six months ended June 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

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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. Gross margins increased by $0.9 and $1.4 million in the first and second quarter of 2011 due to this mechanism. In the second quarter, retail revenues and margins increased by $2.2 million due to higher retail loads driven by warmer temperatures and an increase in the number of retail customers.

Due to unprecedented drought conditions, reliability and outage issues in the Gulf coast region of TNMP's operations resulted in additional operating expenses of $0.7 million for the second quarter of 2011. In addition, an increase in allocation of corporate overhead costs of $1.1 million and higher labor costs also increased operating expenses. For the six months ended June 30, 2011, vegetation management costs of $0.2 million and a $0.2 million write-off of rate case expenses associated with the 2010 TNMP rate case increased operating expenses.

In the second quarter of 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 retroactively to July 20, 2006. See Note 10.

The increase in depreciation and amortization relates to the amortization of Hurricane Ike restoration cost and higher depreciation due to increases in transmission 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 June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
							(In millions)
Total revenues	$	126.0		$	119.9		$	6.1		$	234.5		$	234.3		$	0.2
Cost of energy	91.3			72.1			19.2			159.3			177.1			(17.8		)
Gross margin	34.7			47.8			(13.1		)	75.2			57.2			18.0
Operating expenses	23.6			21.3			2.3			42.6			41.7			0.9
Depreciation and amortization	0.4			0.2			0.2			0.6			0.5			0.1
Operating income	10.8			26.3			(15.5		)	32.0			15.0			17.0
Other income (deductions)	(0.2		)	(0.1		)	(0.1		)	(0.3		)	(0.1		)	(0.2		)
Net interest charges	(0.1		)	(0.4		)	0.3			(0.3		)	(0.7		)	0.4
Earnings before income taxes	10.4			25.9			(15.5		)	31.3			14.2			17.1
Income (taxes)	(3.7		)	(9.3		)	5.6			(11.2		)	(5.1		)	(6.1		)
Segment earnings	$	6.6		$	16.6		$	(10.0	)	$	20.1		$	9.1		$	11.0

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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 June 30,									Six Months Ended June 30,
	Total			Cost of			Gross			Total			Cost of			Gross
	Revenues			Energy			Margin			Revenues			Energy			Margin
							(In millions)
Weather	$	6.8		$	4.4		$	2.4		$	5.2		$	3.4		$	1.8
Customer growth/usage	10.3			7.0			3.3			15.8			10.6			5.2
Retail margins	(11.0		)	(5.0		)	(6.0		)	(20.8		)	(7.7		)	(13.1		)
Unrealized economic hedges	—			12.8			(12.8		)	—			(24.1		)	24.1
Total increase (decrease)	$	6.1		$	19.2		$	(13.1	)	$	0.2		$	(17.8	)	$	18.0

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



	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
			(In millions, except customers)
Residential	$	74.1	$	75.3	$	(1.2	)	$	137.7	$	150.0	$	(12.3	)
Commercial	48.6		40.8		7.8			89.7		76.4		13.3
Other	3.3		3.8		(0.5		)	7.1		7.9		(0.8		)
	$	126.0	$	119.9	$	6.1		$	234.5	$	234.3	$	0.2
Actual customers (thousands) ^(1,2)	216.6		216.1		0.5			216.6		216.1		0.5


(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 June 30,			Six Months Ended June 30,
	2011	2010	Change	2011	2010	Change
		(Gigawatt hours) ⁽¹⁾
Residential	570.1	549.3	20.8	1,058.7	1,099.4	(40.7	)
Commercial	459.1	347.5	111.6	828.3	627.3	201.0
	1,029.2	896.8	132.4	1,887.0	1,726.7	160.3


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

During the three and six months ended June 30, 2011, total revenues increased due to favorable weather and an increase in MWh sales, which were partially offset by a decrease in the average revenue rates. The total amount of cost of energy increased due to higher volumes, but was partially offset by lower purchased power costs per MWh. Overall, energy costs were higher and more than offset the increase in revenues resulting in decreased gross margin, excluding the effects of mark-to-market on unrealized economic hedges.

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

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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 or sales accounting are marked to market through current period earnings as required by GAAP. First quarter of 2010 market energy price decreases were partially offset by second quarter activity. During the second quarter of 2011, market energy prices decreased, which resulted in unrealized mark-to-market losses on certain of First Choice's forward supply contracts. These losses were in contrast to the gains experienced in the second quarter of 2010 when market energy prices increased. 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 $5.6 million in 2011 compared with losses of $18.5 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 lower average final bills attributable to lower sales prices have reduced bad debt. As a result, bad debt expense decreased, which increased segment earnings by $0.2 million in the second quarter of 2011 and $1.5 million year-to-date 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 and increased focus on identifying new customer prospects that are more likely to demonstrate desired payment behavior. First Choice is focusing its marketing efforts on commercial customers and customers with established payment patterns. Beginning in 2009, First Choice also increased the credit score required to become a customer and expanded the circumstances where customers are required to provide advance deposits to obtain service, or both. These practices are refined periodically based on 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.

Corporate and Other

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
				(In millions)
Total revenues	$	(9.6	)	$	(9.7	)	$	0.1		$	(18.5	)	$	(19.4	)	$	0.9
Cost of energy	(9.6		)	(9.6		)	—			(18.4		)	(19.2		)	0.8
Gross margin	—			(0.1		)	0.1			(0.1		)	(0.2		)	0.1
Operating expenses	(2.2		)	(3.8		)	1.6			(5.6		)	(7.1		)	1.5
Depreciation and amortization	4.3			4.2			0.1			8.5			8.3			0.2
Operating income (loss)	(2.1		)	(0.5		)	(1.6		)	(3.0		)	(1.4		)	(1.6		)
Equity in net earnings (loss) of Optim Energy	—			(3.9		)	3.9			—			(8.2		)	8.2
Other income (deductions)	(1.7		)	(1.6		)	(0.1		)	(3.3		)	(2.8		)	(0.5		)
Net interest charges	(5.0		)	(5.0		)	—			(10.1		)	(10.2		)	0.1
Earnings (loss) before income taxes	(8.8		)	(10.9		)	2.1			(16.5		)	(22.7		)	6.2
Income (taxes) benefit	3.7			4.4			(0.7		)	6.6			9.1			(2.5		)
Segment earnings (loss)	$	(5.2	)	$	(6.6	)	$	1.4		$	(9.8	)	$	(13.5	)	$	3.7

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, which are further explained below.

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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 did not record 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.

The table below summarizes the operating results for Optim Energy:



	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
	(In millions)
Total operating revenues	$	77.3		$	86.9		$	(9.6	)	$	151.2		$	192.5		$	(41.3	)
Cost of energy	54.9			61.2			(6.3		)	112.9			138.5			(25.6		)
Gross margin	22.4			25.7			(3.3		)	38.4			53.9			(15.5		)
Operating expenses	18.1			14.6			3.5			36.7			34.1			2.6
Depreciation and amortization	13.1			12.9			0.2			24.7			24.9			(0.2		)
Operating income (loss)	(8.8		)	(1.8		)	(7.0		)	(23.0		)	(5.1		)	(17.9		)
Other income (deductions)	0.2			—			0.2			0.3			0.1			0.2
Net interest charges	(4.0		)	(4.7		)	0.7			(8.0		)	(9.3		)	1.3
Earnings (loss) before income taxes	(12.6		)	(6.4		)	(6.2		)	(30.7		)	(14.4		)	(16.3		)
Income (tax) on margin	(0.1		)	—			(0.1		)	(0.1		)	(0.1		)	—
Net earnings (loss)	$	(12.7	)	$	(6.5	)	$	(6.2	)	$	(30.9	)	$	(14.4	)	$	(16.5	)

50 percent of net earnings (loss)	$	(6.4	)	$	(3.2	)	$	(3.2	)	$	(15.4	)	$	(7.2	)	$	(8.2	)
Amortization of basis difference in Optim Energy	—			(0.6		)	0.6			—			(1.0		)	1.0
Post-impairment loss not recorded under GAAP	6.4			—			6.4			15.4			—			15.4
PNMR equity in net earnings (loss) of Optim Energy	$	—		$	(3.9	)	$	3.9		$	—		$	(8.2	)	$	8.2

Optim Energy's current strategy and near-term focus is on utilizing cash flow from operations to reduce debt and optimizing its generation assets as a stand-alone independent power producer. The goal is to position Optim Energy to optimize its performance in the current market with the expectation of being able to take advantage of any economic recovery in the power and gas market over the next several years.

Optim Energy's management evaluates the results of operations on an on-going earnings before interest, income taxes, depreciation, amortization, mark-to-market, and certain other items (“On-going EBITDA”) basis. Twin Oaks, Cogen, and Cedar Bayou 4 generating stations comprise Optim Energy's core business. Revenue related to power sales and purchases is included net in operating revenues. Costs related to fuel purchases and sales are recorded net in cost of energy.

Optim Energy has a hedging program that varies at any given time depending on current market conditions and other factors. Optim Energy has designated a long-term power and steam contract as a normal sale under GAAP. At June 30, 2011, all other transactions are designated as economic hedges that are required to be marked to market. On-going EBITDA for the three months ended June 30, 2011 and 2010 excludes forward mark-to-market gains of $5.9 million and losses of $1.3 million. On-going EBITDA for the six months ended June 30, 2011 and 2010 excludes forward mark-to-market gains of $2.6 million and $3.0 million.

Low power prices resulted in a decline in Optim Energy's average realized power price in 2011. Optim Energy offset some of the decline through optimization of generation and sales of excess emission allowances. Operating expenses in the second

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quarter of 2011 increased by $3.5 million mainly due to a counterparty's emergence from bankruptcy in 2010, which resulted in the reversal of a previous reserve, as well as increased incentive compensation costs.

On-going EBITDA excludes purchase accounting amortizations related to the acquisitions of Twin Oaks and Cogen. Amortization related to out of market contracts decreased total operating revenues $3.7 million and $7.3 million for the three months and six months ended June 30, 2011, and $4.2 million and $8.2 million for the three months and six months ended June 30, 2010. Amortization for out of market contracts will continue through 2021. In addition, cost of energy includes $1.6 million and $4.1 million for the three months and six months ended June 30, 2011, and $1.3 million and $2.6 million for the three months and six months ended June 30, 2010. The amortizations for emission allowances are recorded as the allowances are used in plant operations, sold, or expire.

On-going EBITDA also excludes interest expense and depreciation. Interest costs were reduced $0.7 million and $1.4 million for the three months and six months ended June 30, 2011, primarily due to interest rate swaps that expired in January 2011. Depreciation expense increased $0.3 million for the three months ended June 30, 2011 and decreased $0.2 million for the six months ended June 30, 2011, primarily due to the retirement of assets.

PNMR had a basis difference between its recorded investment in Optim Energy and 50 percent of Optim Energy's equity resulting from Optim Energy's acquisition of the Twin Oaks plant from PNMR in 2007. The portion of the basis difference related to contract amortization ended in 2010 and other basis differences, including a difference related to emission allowances that would have continued through the life of the Twin Oaks plant, were taken into account in the impairment discussed above. The basis difference adjustment detailed above relates primarily to contract amortization with insignificant offsets related to the other minor basis difference components.

On March 11, 2011, the Cedar Bayou 4 facility was forced into an unplanned outage due to mechanical failure; the plant has not returned to service as of June 30, 2011. Optim Energy owns 50% of Cedar Bayou 4. The outage is not expected to have a material impact on Optim Energy's financial results or position due to anticipated insurance recoveries.

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

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



	Six Months Ended June 30,
	2011				2010			Change
				(In millions)
Net cash flows from:
Operating activities	$	84.7			$	76.2		$	8.5
Investing activities	(138.6		)		(138.6		)	—
Financing activities	52.4				66.9			(14.5		)
Net change in cash and cash equivalents	$	(1.4	)		$	4.5		$	(5.9	)

The changes in PNMR's cash flows from operating activities relate primarily to the January 2010 payment of the $31.9 million settlement of the California energy crisis legal proceeding. Improved collections under the FPPAC at PNM of $20.9 million and decreases in posted collateral requirements of $16.3 million at First Choice and $3.5 million at PNM also contributed to the change. The increases were partially offset by lower net income tax refunds in 2011 of $1.8 million compared to $63.4 million in 2010.

PNMR's cash flows from investing activities relate primarily to increases in construction expenditures in 2011 of $12.3 million at PNM and $10.1 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 $16.4 million investment in Optim Energy in 2010. Construction expenditures were funded primarily through cash flows from operating activities and short-term borrowings in both 2011 and 2010.

The changes in cash flows from financing activities primarily relate to payments received on PVNGS firm-sales contract

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arrangements of $2.6 million in 2011 compared to $15.2 million in 2010 as those contracts expired on December 31, 2010. A $5.0 million reduction in net short-term borrowings also contributed to the change.

Financing Activities

See Note 7 for information concerning the Company’s financing activities during the six months ended June 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.

Capital Requirements

Total capital requirements consist of construction expenditures and cash dividend requirements for both common and preferred stock. The Series A convertible preferred stock is 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, and purchasing nuclear fuel. Projections, including amounts expended through June 30, 2011, for total capital requirements for 2011 are $409.2 million, including construction expenditures of $363.0 million. Total capital requirements for the years 2011-2015 are projected to be $1,611.6 million, including construction expenditures of $1,380.3 million. These amounts do not include forecasted construction expenditures of Optim Energy or the costs of any pollution control equipment that might ultimately be required as a result of the 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 the EPA's FIP decision on capital requirements.

During the six months ended June 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.

As discussed in Note 11, Optim Energy’s credit facility expires in May 2012. During 2010, PNMR made capital contributions of $20.3 million to Optim Energy, which Optim Energy used to reduce debt under its credit facility. PNMR does not have any contractual requirement to provide Optim Energy with additional financial resources. If Optim Energy were to undertake additional projects, which require funds that would exceed the capacity of its current credit facility and Optim Energy is unable to obtain additional financing capabilities, PNMR and ECJV may be asked to provide additional funding, but such funding would be at the option of PNMR and ECJV and no assurance can be given that such funding will be available to Optim Energy. PNMR is unable to predict if additional funding will be requested or, if requested, the amount or timing of additional funds, if any, that would be provided to Optim Energy. However, as of the date of this report, PNMR does not anticipate making additional contributions to Optim Energy.

Liquidity

PNMR’s liquidity arrangements include the PNMR Facility and the PNM Facility both of which primarily expire in August 2012 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 $7.0 million to $33.0 million during the three months ended June 30, 2011 and from zero to $33.0 million during the six months ended June 30, 2011. Borrowings under the PNM Facility ranged from $242.0 million to $279.0 million during the three months ended June 30, 2011 and from $190.0 million to $279.0 million during the six months ended June 30, 2011. There have been no borrowings under the TNMP Revolving Credit Facility during 2011. At June 30, 2011, average interest rates were 1.44% for the PNMR Facility and 0.84% for the PNM Facility.

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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 June 30, 2011.

The PNMR Facility and the PNM Facility will need to be renegotiated or replaced prior to their expirations in order to provide sufficient liquidity to finance operations and construction expenditures. The availability of such credit facilities, including the amounts for borrowing thereunder and the terms and conditions, will depend on the credit markets at that time, as well as the Company’s credit ratings and operating results. PNMR also has a line of credit with a local financial institution that expires in August 2012. As of August 2, 2011, the Company had short-term debt outstanding of $307.0 million.

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 current and future liquidity arrangements. However, if market difficulties experienced during the recession resurge or worsen, the Company may not be able to access the capital markets or renew credit facilities when they expire. 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 are set forth under the heading Liquidity in the MD&A contained in the 2010 Annual Reports on Form 10-K.

A summary of liquidity arrangements as of August 2, 2011 is as follows:



	PNMR Separate		PNM Separate		TNMP Separate		PNMR Consolidated
			(In millions)
Financing Capacity:
Revolving credit facility	$	542.0	$	386.0	$	75.0	$	1,003.0
Local lines of credit	5.0		—		—		5.0
Total financing capacity	$	547.0	$	386.0	$	75.0	$	1,008.0

Amounts outstanding as of August 2, 2011:
Revolving credit facility	$	19.0	$	288.0	$	—	$	307.0
Local lines of credit	—		—		—		—
Total short-term debt outstanding	19.0		288.0		—		307.0

Letters of credit	72.9		39.2		0.3		112.4

Total short–term debt and letters of credit	$	91.9	$	327.2	$	0.3	$	419.4

Remaining availability as of August 2, 2011	$	455.1	$	58.8	$	74.7	$	588.6
Invested cash as of August 2, 2011	$	10.3	$	10.7	$	—	$	21.0

The above table excludes intercompany debt. 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. The financing capacities of the PNMR Facility and the PNM Facility will reduce by $25.0 million and $18.0 million in August 2011 according to their terms. The Company does not believe the scheduled reduction in the facilities will have a significant impact on PNMR’s and PNM’s liquidity.

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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 $600.0 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.

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.

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Capital Structure

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



	June 30, 2011		December 31, 2010
PNMR
PNMR common equity	47.9	%	47.8	%
Convertible preferred stock	3.1	%	3.1	%
Preferred stock of subsidiary	0.4	%	0.4	%
Long-term debt	48.6	%	48.7	%
Total capitalization	100.0	%	100.0	%

PNM
PNM common equity	51.1	%	51.3	%
Preferred stock	0.5	%	0.5	%
Long-term debt	48.4	%	48.2	%
Total capitalization	100.0	%	100.0	%

TNMP
Common equity	59.4	%	59.4	%
Long-term debt	40.6	%	40.6	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In 2010, PNMR’s interests in generating plants, through PNM and Optim Energy, emitted approximately 8.9 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 the 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 CO₂emissions.

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 7 MW of which were in service at June 30, 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 CO₂based 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.

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EPA Regulation

In April 2007, the U.S. Supreme Court held that the EPA has the authority to regulate GHG under the Clean Air Act. 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, the 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 the EPA to regulate GHG from new and existing stationary sources such as power plants and new motor vehicles.

On May 13, 2010, the 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. 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. Phase 2 began July 1, 2011 and addresses any large source of GHG that was not previously subject to the PSD and Title V regulatory programs. The EPA has indicated that it will adopt a Phase 3, to be effective in July 2013, which may phase in even smaller GHG sources.

On December 23, 2010, EPA announced a proposed rulemaking timeline for Clean Air Act 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 will extend the deadline for proposing NSPS for GHG emissions from electric generating units from July 26, 2011 until September 30, 2011. The EPA stated that it needs more time to evaluate information it received during listening sessions with industry, state governments, and environmentalists to establish "smart, cost-effective, and productive standards." The deadline for EPA to publish the final standards is still May 26, 2012. The Clean Air Act’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 112th 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. For example, see the discussion in Note 9 under the caption 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

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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.

Seven western states, including New Mexico, and three Canadian provinces have 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 has created several subcommittees to develop detailed implementation recommendations. Under the WCI recommendations, GHG 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. California recently announced that the soonest their proposed cap-and-trade program will start is 2013. Also, several market elements including allowance tracking and a trading market must be established by WCI. PNM filed testimony in the rulemaking hearing estimating the cost of electricity to PNM’s customers would increase from a nominal amount in 2012 to $85 million in 2020 due solely to the NMED’s proposed rule. 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. At its meeting on August 1, 2011, the EIB decided that it will conduct hearings beginning on November 8, 2011 to determine whether or not the NMED rule should be repealed. 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 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 proposed 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. The hearings will begin at the conclusion of the hearings on the NMED rule discussed above. 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

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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. 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. In addition, although the New Mexico 2011 legislative session did not repeal these rules, it is possible future action by the EIB or a future legislative session might do so.

Impact of International Accords, Indirect Consequences, and Physical Impacts

Approximately 82.8% of PNM’s owned and leased generating capacity 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. All of Optim Energy’s owned generation produces GHG and is located within the United States. Based on current forecasts, the Company does not expect its output of GHG to 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, First Choice, and Optim Energy have operations in the Gulf coast area of Texas, which experiences periodic hurricanes. In addition to potentially causing physical damage to Company or Optim Energy owned facilities, which disrupt the ability to generate, transmit, and/or distribute energy, hurricanes can temporarily reduce customers’ usage and demand for energy.

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.

As of June 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:


•	Conditions affecting the Company’s ability to access the financial markets and the Company’s or Optim Energy’s ability to negotiate new credit facilities for those expiring in 2012, 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 or Optim Energy 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 recession and its impacts on the electricity usage of the Company’s customers,


•	State and federal regulatory, legislative, and judicial decisions and actions, including the outcomes of PNM’s pending electric rate case and transmission rate case, and appeals of prior regulatory proceedings,


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


•	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 the increased costs of rights-of-way renewals on Native American lands through rates charged to customers,


•	The ongoing risks relating to PNMR’s ownership interest in Optim Energy,


•	Uncertainties surrounding PNMR’s assessments of strategic alternatives for its competetive businesses, First Choice and Optim Energy,


•	The risk that Optim Energy requires additional financial sources to expand its generation capacity, or otherwise, but is unable to identify and implement profitable acquisitions or that PNMR and ECJV will not agree to make additional capital contributions to Optim Energy,

•

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 and Optim Energy 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 and Optim Energy have interests,

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


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


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


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


•	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,


•	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 less economically,


•	Changes in ERCOT protocols,


•	Changes in the cost of power acquired by First Choice and changes in the retail price of power in ERCOT,


•	The ability of First Choice to attract and retain customers,


•	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,


•	Changes in applicable accounting principles, and


•	The performance of state, regional, and national economies.

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.

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 Committee are 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 specifically 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.

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:

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	Trading		Economic Hedges			Total
Six Months Ended June 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	—		5,576			5,576
Changes in fair value	—		1,420			1,420
Net change recorded as mark-to-market	—		6,996			6,996
Net change recorded as regulatory assets and liabilities	—		(398		)	(398		)
Unearned/prepaid option premiums	—		1,666			1,666
Settlement of de-designated cash flow hedges	—		250			250
Net fair value at end of period	$	—	$	(14,461	)	$	(14,461	)



	Trading			Economic Hedges			Total
Six Months Ended June 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	(594		)	7,111			6,517
Changes in fair value	(33		)	(31,236		)	(31,269		)
Net change recorded as mark-to-market	(627		)	(24,125		)	(24,752		)
Unearned/prepaid option premiums	—			1,086			1,086
Settlement of de-designated cash flow hedges	—			1,246			1,246
Net fair value at end of period	$	612		$	(19,576	)	$	(18,964	)

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 June 30, 2011



	Less than 1 Year			1-3 Years			4+ Years			Total
				(In thousands)
Economic hedges
Prices actively quoted	$	(11,881	)	$	(2,588	)	$	—		$	(14,469	)
Prices provided by other external sources	(1,041		)	(2,756		)	(587		)	(4,384		)
Prices based on models and other valuations	4,477			(85		)	—			4,392
Total	$	(8,445	)	$	(5,429	)	$	(587	)	$	(14,461	)

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 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

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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 six months ended June 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 six months ended June 30, 2011, the average GEaR amount was $2.7 million, with high and low GEaR amounts for the period of $4.4 million and $1.3 million. The total GEaR amount at June 30, 2011 was $2.9 million. For the six months ended June 30, 2010, the average GEaR amount for these transactions was $3.4 million, with high and low GEaR amounts for the period of $5.4 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 $0.5 million at June 30, 2011. For the six months ended June 30, 2011, the high, low and average VaR amounts were $0.8 million, $0.1 million and $0.3 million. For the six months ended June 30, 2010, the high, low and average VaR amounts were $2.3 million, $0.4 million and $1.3 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 six months ended June 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 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.

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The following table provides information related to PNMR’s credit exposure as of June 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 June 30, 2011 will mature in less than two years.

Schedule of Credit Risk Exposure

June 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	$	3,352	3	$	2,113
Non-investment grade	47		—	—
Internal ratings:
Investment grade	15		—	—
Non-investment grade	416		—	—
Total	$	3,830		$	2,113

(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 June 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 June 30, 2011 was $0.9 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 4.3% if interest rates were to decline by 50 basis points from their levels at June 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 August 2, 2011, PNMR had $307.0 million of consolidated short-term debt outstanding under its revolving credit facilities and local line of credit, which allow for a maximum aggregate borrowing capacity of $1,008.0 million. These facilities bear interest at variable rates, which averaged 0.87% of borrowings, 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 $647.0 million at June 30, 2011, of which 33.6% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at June 30, 2011, the decrease in the fair value of the fixed-rate securities would be 5.3%, or $11.5 million. The securities held by TNMP in trusts for pension and other post-employment benefits had an estimated fair value of $71.0 million at June 30, 2011, of which 30.2% 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 June 30, 2011, the decrease in the fair value of the fixed-rate securities would be 6.5%, or $1.4 million.

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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 June 30, 2011. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 53.6% of the securities held by the various PNM trusts as of June 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 49.5% of the securities held by the TNMP trusts as of June 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 target of investing 20% of its pension assets in the alternatives asset class, which amounted to 20.5% as of June 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.

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 June 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 June 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 June 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 Notice of Intent to Sue


•	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


•	PNM – Emergency FPPAC


•	PNM – 2010 Electric Rate Case


•	PNM – Transmission 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.

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.

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 February 17, 2009 (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed February 20, 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 adopted on August 4, 2005 (incorporated by reference to Exhibit 3.2.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.1	PNMR	Agreement of Resignation, Appointment and Acceptance, effective as of June 1, 2011, among PNMR, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for March 15, 2005 PNMR Indenture)

4.2	PNM	Agreement of Resignation, Appointment and Acceptance, effective as of May 1, 2011, among PNM, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for March 11, 1998 PNM Indenture)

4.3	PNM	Agreement of Resignation, Appointment and Acceptance, effective as of June 1, 2011, among PNM, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for August 1, 1998 PNM Indenture)

4.4	TNMP	Agreement of Resignation, Appointment and Acceptance, effective as of June 1, 2011, among TNMP, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for March 23, 2009 TNMP Indenture)

10.1	PNMR	Letter Agreement, dated as of May 5, 2011, between PNM Resources, Inc. and Cascade Investment, L.L.C.

12.1	PNMR	Ratio of Earnings to Fixed Charges

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

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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

Note: As permitted by SEC rules, the Company will file an amendment to its Quarterly Report on Form 10-Q that will contain information included herein as required in eXtensible Business Reporting Language ("XBRL") format no later than 30 days after the date of the filing of this Quarterly Report.

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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:	August 8, 2011	/s/ Thomas G. Sategna
		Thomas G. Sategna
		Vice President and Corporate Controller
		(Officer duly authorized to sign this report)

102

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