10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 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

Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act).

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

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES          NO  ü

As of April 28, 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 April 28, 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 April 28, 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.

2

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

INDEX

	Page No.
GLOSSARY	4
PART I.  FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS (UNAUDITED)
PNM RESOURCES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings (Loss)	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 (Loss)	12
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	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	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 Common Stockholder’s 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	68
ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	90
ITEM 4.  CONTROLS AND PROCEDURES	95
PART II.  OTHER INFORMATION
ITEM 1.  LEGAL PROCEEDINGS	96
ITEM 1A.  RISK FACTORS	97
ITEM 6.  EXHIBITS	97
SIGNATURE	98

3

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
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)
Continental	Continental Energy Systems, L.L.C.
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
NERC	North American Electric Reliability Council
NMAG	New Mexico Attorney General
NMED	New Mexico Environment Department
NMIEC	New Mexico Industrial Energy Consumers Inc.

4

NMPRC	New Mexico Public Regulation Commission
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
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
Pyramid	Tri-State Pyramid Unit 4
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

5

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)

(Unaudited)

	Three Months Ended March 31,
	2011				2010
	(In thousands, except per share amounts)
Electric Operating Revenues		$	387,663			$	383,457
Operating Expenses:
Cost of energy			158,507				190,888
Administrative and general			58,465				62,785
Energy production costs			48,652				53,885
Depreciation and amortization			38,473				37,279
Transmission and distribution costs			16,877				13,890
Taxes other than income taxes			14,469				14,187
Total operating expenses			335,443				372,914
Operating income			52,220				10,543
Other Income and Deductions:
Interest income			4,028				5,027
Gains on investments held by NDT			5,902				1,743
Other income			995				10,137
Equity in net earnings (loss) of Optim Energy			-				(4,352	)
Other deductions			(3,072	)			(1,841	)
Net other income (deductions)			7,853				10,714
Interest Charges			30,615				31,410
Earnings (Loss) before Income Taxes			29,458				(10,153	)
Income Taxes (Benefit)			9,506				(4,939	)
Net Earnings (Loss)			19,952				(5,214	)
(Earnings) Attributable to Valencia Non-controlling Interest			(3,183	)			(3,103	)
Preferred Stock Dividend Requirements of Subsidiary			(132	)			(132	)
Net Earnings (Loss) Attributable to PNMR		$	16,637			$	(8,449	)
Net Earnings (Loss) Attributable to PNMR per Common Share:
Basic		$	0.18			$	(0.09	)
Diluted		$	0.18			$	(0.09	)
Dividends Declared per Common Share		$	0.125			$	0.125

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

6

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2011			December 31, 2010
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents		$	12,940		$	15,404
Accounts receivable, net of allowance for uncollectible accounts of $9,026 and $11,178			94,275			97,245
Unbilled revenues			61,130			71,453
Other receivables			57,523			58,901
Affiliate receivables			2,923			1,661
Materials, supplies, and fuel stock			51,788			52,479
Regulatory assets			32,197			36,292
Commodity derivative instruments			17,833			15,999
Income taxes receivable			97,201			97,450
Current portion of accumulated deferred income taxes			886			886
Other current assets			91,672			96,110
Total current assets			520,368			543,880
Other Property and Investments:
Investment in PVNGS lessor notes			90,897			103,871
Investments held by NDT			167,137			156,922
Other investments			17,925			18,791
Non-utility property, net of accumulated depreciation of $2,524 and $2,307			11,967			7,333
Total other property and investments			287,926			286,917
Utility Plant:
Plant in service and plant held for future use			4,895,632			4,860,614
Less accumulated depreciation and amortization			1,649,799			1,626,693
			3,245,833			3,233,921
Construction work in progress			143,784			137,622
Nuclear fuel, net of accumulated amortization of $31,786 and $26,247			76,665			72,901
Net utility plant			3,466,282			3,444,444
Deferred Charges and Other Assets:
Regulatory assets			489,694			502,467
Goodwill			321,310			321,310
Other intangible assets, net of accumulated amortization of $5,476 and $5,414			26,363			26,425
Commodity derivative instruments			6,247			5,264
Other deferred charges			95,536			94,376
Total deferred charges and other assets			939,150			949,842
		$	5,213,726		$	5,225,083

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

7

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2011				December  31, 2010
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt		$	224,000			$	222,000
Current installments of long-term debt			2,252				2,252
Accounts payable			88,132				95,969
Accrued interest and taxes			70,503				47,783
Regulatory liabilities			848				724
Commodity derivative instruments			25,520				31,407
Dividends declared			11,562				11,565
Other current liabilities			81,377				108,424
Total current liabilities			504,194				520,124
Long-term Debt			1,563,756				1,563,595
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes			535,537				540,106
Accumulated deferred investment tax credits			17,510				18,089
Regulatory liabilities			355,323				342,465
Asset retirement obligations			78,207				76,637
Accrued pension liability and postretirement benefit cost			261,698				270,172
Commodity derivative instruments			10,567				12,831
Other deferred credits			148,896				147,616
Total deferred credits and other liabilities			1,407,738				1,407,916
Total liabilities			3,475,688				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)			1,289,923				1,290,465
Accumulated other comprehensive income (loss), net of income taxes			(67,992	)			(68,666	)
Retained earnings			320,150				314,943
Total PNMR common stockholders’ equity			1,542,081				1,536,742
Non-controlling interest in Valencia			84,428				85,177
Total equity			1,726,509				1,721,919
		$	5,213,726			$	5,225,083

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

8

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March  31,
	2011				2010
	(In thousands)
Cash Flows From Operating Activities:
Net earnings (loss)		$	19,952			$	(5,214	)
Adjustments to reconcile net earnings (loss) to net cash flows from operating activities:
Depreciation and amortization			48,458				44,318
PVNGS firm-sales contract revenue			(2,558	)			(14,329	)
Bad debt expense			5,062				6,397
Deferred income tax expense (benefit)			9,312				(4,334	)
Equity in net (earnings) loss of Optim Energy			-				4,352
Net unrealized (gains) losses on derivatives			(11,002	)			33,355
Realized (gains) on investments held by NDT			(5,902	)			(1,743	)
Stock based compensation expense			945				1,427
Other, net			1,503				(807	)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues			8,231				16,113
Materials, supplies, and fuel stock			691				98
Other current assets			8,836				(70,817	)
Other assets			(918	)			(4,594	)
Accounts payable			(7,838	)			(8,078	)
Accrued interest and taxes			22,969				22,950
Other current liabilities			(26,354	)			(21,680	)
Other liabilities			(12,649	)			(10,670	)
Net cash flows from operating activities			58,738				(13,256	)
Cash Flows From Investing Activities:
Additions to utility and non-utility plant			(63,129	)			(67,542	)
Proceeds from sales of investments held by NDT			48,120				20,699
Purchases of investments held by NDT			(48,938	)			(21,614	)
Return of principal on PVNGS lessor notes			15,374				14,216
Other, net			(365	)			165
Net cash flows from investing activities			(48,938	)			(54,076	)

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

9

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March  31,
	2011				2010
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net			2,000				89,973
Proceeds from stock option exercise			1,265				483
Purchases to satisfy awards of common stock			(2,752	)			(1,446	)
Excess tax (shortfall) from stock-based payment arrangements			-				(106	)
Dividends paid			(11,563	)			(11,564	)
Equity transactions with Valencia’s owner			(3,932	)			(3,132	)
Payments received on PVNGS firm-sales contracts			2,558				7,593
Proceeds from transmission interconnection agreements			152				-
Debt issuance costs and other			8				(124	)
Net cash flows from financing activities			(12,264	)			81,677
Change in Cash and Cash Equivalents			(2,464	)			14,345
Cash and Cash Equivalents at Beginning of Period			15,404				14,641
Cash and Cash Equivalents at End of Period		$	12,940			$	28,986
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest		$	6,061			$	5,349
Income taxes paid (refunded), net		$	-			$	(2,020	)

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

10

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

	Attributable to PNMR																			Non- controlling Interest in Valencia				Total Equity
	Preferred Stock, Series A			PNMR Common Stockholders’ Equity
				Common								Retained
				Stock				AOCI				Earnings				Total
	(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			-			1,265				-				-				1,265				-				1,265
Purchases to satisfy awards of common stock			-			(2,752	)			-				-				(2,752	)			-				(2,752	)
Stock based compensation expense			-			945				-				-				945				-				945
Valencia’s transactions with its owner			-			-				-				-				-				(3,932	)			(3,932	)
Net earnings excluding subsidiary preferred stock dividends			-			-				-				16,769				16,769				3,183				19,952
Subsidiary preferred stock dividends			-			-				-				(132	)			(132	)			-				(132	)
Total other comprehensive income			-			-				674				-				674				-				674
Dividends declared on common stock			-			-				-				(11,430	)			(11,430	)			-				(11,430	)
Balance at March 31, 2011		$	100,000		$	1,289,923			$	(67,992	)		$	320,150			$	1,542,081			$	84,428			$	1,726,509

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

11

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended March  31,
	2011				2010
	(In thousands)
Net Earnings (Loss)		$	19,952			$	(5,214	)
Other Comprehensive Income:
Unrealized Gain on Investment Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(3,453) and $(1,222)			5,269				1,865
Reclassification adjustment for (gains) included in net earnings (loss), net of income tax expense of $2,070 and $610			(3,158	)			(931	)
Pension liability adjustment, net of income tax (expense) benefit of $1,026 and $147			(1,614	)			(223	)
Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense) of $(9) and $(5,056)			23				7,617
Reclassification adjustment for (gains) losses included in net earnings (loss), net of income tax expense (benefit) of $(87) and $4,192			154				(6,315	)
Total Other Comprehensive Income			674				2,013
Comprehensive Income (Loss)			20,626				(3,201	)
Comprehensive (Income) Attributable to Valencia Non-controlling Interest			(3,183	)			(3,103	)
Preferred Stock Dividend Requirements of Subsidiary			(132	)			(132	)
Comprehensive Income (Loss) Attributable to PNMR		$	17,311			$	(6,436	)

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

12

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March  31,
	2011				2010
	(In thousands)
Electric Operating Revenues		$	234,238			$	230,536
Operating Expenses:
Cost of energy			89,214				86,434
Administrative and general			34,337				37,686
Energy production costs			48,652				53,885
Depreciation and amortization			23,735				22,852
Transmission and distribution costs			11,607				9,308
Taxes other than income taxes			8,528				7,914
Total operating expenses			216,073				218,079
Operating income			18,165				12,457
Other Income and Deductions:
Interest income			4,057				4,935
Gains on investments held by NDT			5,902				1,743
Other income			301				10,037
Other deductions			(986	)			(623	)
Net other income (deductions)			9,274				16,092
Interest Charges			18,080				18,077
Earnings before Income Taxes			9,359				10,472
Income Taxes			2,395				2,921
Net Earnings			6,964				7,551
(Earnings) Attributable to Valencia Non-controlling Interest			(3,183	)			(3,103	)
Net Earnings Attributable to PNM			3,781				4,448
Preferred Stock Dividends Requirements			(132	)			(132	)
Net Earnings Available for PNM Common Stock		$	3,649			$	4,316

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

13

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
	2011			2010
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents		$	55		$	10,336
Accounts receivable, net of allowance for uncollectible accounts of $1,483 and $1,483			55,838			58,785
Unbilled revenues			33,240			39,053
Other receivables			55,591			56,951
Affiliate receivables			8,603			8,605
Materials, supplies, and fuel stock			49,114			49,454
Regulatory assets			30,403			35,835
Commodity derivative instruments			2,245			1,443
Income taxes receivable			76,941			76,941
Other current assets			47,213			46,635
Total current assets			359,243			384,038
Other Property and Investments:
Investment in PVNGS lessor notes			90,897			103,871
Investments held by NDT			167,137			156,922
Other investments			5,211			5,068
Non-utility property			976			976
Total other property and investments			264,221			266,837
Utility Plant:
Plant in service and plant held for future use			3,848,202			3,818,722
Less accumulated depreciation and amortization			1,272,769			1,259,957
			2,575,433			2,558,765
Construction work in progress			122,419			115,628
Nuclear fuel, net of accumulated amortization of $31,786 and $26,247			76,665			72,901
Net utility plant			2,774,517			2,747,294
Deferred Charges and Other Assets:
Regulatory assets			349,076			357,944
Goodwill			51,632			51,632
Commodity derivative instruments			7			-
Other deferred charges			67,875			67,828
Total deferred charges and other assets			468,590			477,404
		$	3,866,571		$	3,875,573

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

14

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,				December 31,
	2011				2010
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt		$	212,000			$	190,000
Short-term debt – affiliate			5,400				-
Accounts payable			56,941				51,931
Affiliate payables			4,869				8,528
Accrued interest and taxes			42,813				25,773
Regulatory liabilities			848				724
Commodity derivative instruments			2,434				3,110
Dividends declared			4,695				39,254
Current portion of accumulated deferred income taxes			9,783				9,783
Other current liabilities			48,545				65,858
Total current liabilities			388,328				394,961
Long-term Debt			1,055,752				1,055,748
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes			435,253				446,657
Accumulated deferred investment tax credits			17,510				18,089
Regulatory liabilities			313,017				299,763
Asset retirement obligations			77,444				75,888
Accrued pension liability and postretirement benefit cost			245,936				253,948
Commodity derivative instruments			1,560				2,009
Other deferred credits			112,556				108,455
Total deferred credits and liabilities			1,203,276				1,204,809
Total liabilities			2,647,356				2,655,518
Commitments and Contingencies (See Note 16)
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 tax			(65,963	)			(66,786	)
Retained earnings			170,445				171,359
Total PNM common stockholder’s equity			1,123,258				1,123,349
Non-controlling interest in Valencia			84,428				85,177
Total equity			1,207,686				1,208,526
		$	3,866,571			$	3,875,573

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

15

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March  31,
	2011			2010
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	6,964		$	7,551
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization		31,601			28,010
PVNGS firm-sales contract revenue		(2,558	)		(14,329	)
Deferred income tax expense		2,395			620
Net unrealized (gains) losses on derivatives		(1,908	)		5,289
Realized (gains) losses on investments held by NDT		(5,902	)		(1,743	)
Other, net		2,324			(203	)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues		8,187			14,181
Materials, supplies, and fuel stock		340			292
Other current assets		6,587			(48,578	)
Other assets		1,240			2,219
Accounts payable		5,010			9,018
Accrued interest and taxes		17,040			17,514
Other current liabilities		(20,821	)		(16,083	)
Other liabilities		(10,596	)		(10,142	)
Net cash flows from operating activities		39,903			(6,384	)
Cash Flows From Investing Activities:
Utility plant additions		(51,520	)		(62,025	)
Proceeds from sales of NDT investments		48,120			20,699
Purchases of NDT investments		(48,938	)		(21,614	)
Return of principal on PVNGS lessor notes		15,374			14,216
Other, net		(144	)		(48	)
Net cash flows from investing activities		(37,108	)		(48,772	)

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

16

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March  31,
	2011			2010
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net		22,000			60,000
Short-term borrowings (repayments) – affiliate, net		5,400			-
Payments received on PVNGS firm-sales contracts		2,558			7,593
Equity transactions with Valencia’s owner		(3,932	)		(3,132	)
Proceeds from transmission interconnection arrangements		152			-
Dividends paid		(39,254	)		(132	)
Net cash flows from financing activities		(13,076	)		64,329
Change in Cash and Cash Equivalents		(10,281	)		9,173
Cash and Cash Equivalents at Beginning of Period		10,336			1,373
Cash and Cash Equivalents at End of Period	$	55		$	10,546
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	5,412		$	3,773
Income taxes paid (refunded), net	$	-		$	-

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

17

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

	Attributable to PNM
	Common Stock			AOCI				Retained Earnings				Total PNM Common Stockholder’s Equity				Non- controlling Interest in  Valencia				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			-			-				-				-				(3,932	)			(3,932	)
Net earnings			-			-				3,781				3,781				3,183				6,964
Total other comprehensive income			-			823				-				823				-				823
Dividends declared on preferred stock			-			-				(132	)			(132	)			-				(132	)
Dividends declared on common stock			-			-				(4,563	)			(4,563	)			-				(4,563	)
Balance at March 31, 2011		$	1,018,776		$	(65,963	)		$	170,445			$	1,123,258			$	84,428			$	1,207,686

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

18

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
	2011				2010
	(In thousands)
Net Earnings		$	6,964			$	7,551
Other Comprehensive Income:
Unrealized Gain on Investment Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(3,453) and $(1,222)			5,269				1,865
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $2,070 and $610			(3,158	)			(931	)
Pension liability adjustment, net of income tax (expense) benefit of $855 and $147			(1,305	)			(223	)
Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense) of $0 and $(2,696)			-				4,114
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(11) and $2,670			17				(4,074	)
Total Other Comprehensive Income			823				751
Comprehensive Income			7,787				8,302
Comprehensive Income Attributable to Valencia Non-controlling Interest			(3,183	)			(3,103	)
Comprehensive Income Attributable to PNM		$	4,604			$	5,199

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

19

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2011				2010
	(In thousands)
Electric Operating Revenues:
Non-affiliates		$	45,028			$	38,591
Affiliate			8,814				9,586
Total electric operating revenues			53,842				48,177
Operating Expenses:
Cost of energy			10,153				9,051
Administrative and general			9,665				9,494
Depreciation and amortization			10,262				10,095
Transmission and distribution costs			5,268				4,581
Taxes other than income taxes			4,770				4,714
Total operating expenses			40,118				37,935
Operating income			13,724				10,242
Other Income and Deductions:
Other income			362				364
Other deductions			(46	)			(18	)
Net other income (deductions)			316				346
Interest Charges			7,299				7,869
Earnings Before Income Taxes			6,741				2,719
Income Taxes			2,578				1,075
Net Earnings		$	4,163			$	1,644

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

20

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2011			December 31, 2010
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents		$	494		$	1
Accounts receivable			13,887			12,742
Unbilled revenues			4,996			5,734
Other receivables			1,965			1,677
Affiliate receivables			3,988			3,956
Materials and supplies			2,640			2,787
Regulatory assets			1,794			457
Current portion of accumulated deferred income taxes			1,876			1,876
Other current assets			307			618
Total current assets			31,947			29,848
Other Property and Investments:
Other investments			268			282
Non-utility property			2,246			2,244
Total other property and investments			2,514			2,526
Utility Plant:
Plant in service and plant held for future use			890,262			885,325
Less accumulated depreciation and amortization			308,340			302,333
			581,922			582,992
Construction work in progress			15,527			12,375
Net utility plant			597,449			595,367
Deferred Charges and Other Assets:
Regulatory assets			140,618			144,522
Goodwill			226,665			226,665
Other deferred charges			12,059			12,029
Total deferred charges and other assets			379,342			383,216
		$	1,011,252		$	1,010,957

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

21

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2011				December 31, 2010
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt – affiliate		$	-			$	1,200
Accounts payable			3,154				5,537
Affiliate payables			521				1,015
Accrued interest and taxes			24,376				23,185
Other current liabilities			3,649				3,292
Total current liabilities			31,700				34,229
Long-term Debt			310,494				310,337
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes			144,510				142,121
Regulatory liabilities			42,306				42,702
Asset retirement obligations			661				648
Accrued pension liability and postretirement benefit cost			15,762				16,224
Other deferred credits			11,340				11,413
Total deferred credits and other liabilities			214,579				213,108
Total liabilities			556,773				557,674
Commitments and Contingencies (See Note 16)
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			427,205				430,108
Accumulated other comprehensive income (loss), net of income tax			(1,549	)			(1,485	)
Retained earnings			28,759				24,596
Total common stockholder’s equity			454,479				453,283
		$	1,011,252			$	1,010,957

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

22

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2011				2010
	(In thousands)
Cash Flows From Operating Activities:
Net earnings		$	4,163			$	1,644
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization			11,050				11,101
Deferred income tax expense (benefit)			2,420				(1,665	)
Other, net			(238	)			10
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues			(407	)			549
Materials and supplies			146				(227	)
Other current assets			(866	)			296
Other assets			(185	)			(856	)
Accounts payable			(2,383	)			(3,620	)
Accrued interest and taxes			1,191				5,047
Other current liabilities			(152	)			(429	)
Other liabilities			(120	)			(585	)
Net cash flows from operating activities			14,619				11,265
Cash Flows From Investing Activities:
Additions to utility and non-utility plant			(10,031	)			(5,207	)
Net cash flows from investing activities			(10,031	)			(5,207	)

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

23

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2011				2010
	(In thousands)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net – affiliate			(1,200	)			(6,000	)
Dividends paid			(2,903	)			-
Debt issuance costs and other			8				(125	)
Net cash flows from financing activities			(4,095	)			(6,125	)
Change in Cash and Cash Equivalents			493				(67	)
Cash and Cash Equivalents at Beginning of Period			1				138
Cash and Cash Equivalents at End of Period		$	494			$	71
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest		$	602			$	865
Income taxes paid (refunded), net		$	-			$	(860	)

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

24

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF 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			-			-				-				4,163			4,163
Total other comprehensive income (loss)			-			-				(64	)			-			(64	)
Dividends declared on common stock			-			(2,903	)			-				-			(2,903	)
Balance at March 31, 2011		$	64		$	427,205			$	(1,549	)		$	28,759		$	454,479

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

25

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
	2011				2010
	(In thousands)
Net Earnings		$	4,163			$	1,644
Other Comprehensive Income (Loss):
Pension liability adjustment, net of income tax (expense) benefit of $171 and $0			(309	)			-
Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $(35) and $350			64				(631	)
Reclassification adjustment for losses included in net earnings, net of income tax (benefit) of $(100) and $(102)			181				185
Total Other Comprehensive Income (Loss)			(64	)			(446	)
Comprehensive Income		$	4,099			$	1,198

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

26

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Significant Accounting Policies and Responsibility for Financial Statements

Financial Statement Preparation

In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at March 31, 2011 and December 31, 2010, and the consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2011 and 2010. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated.

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

These Condensed Consolidated Financial Statements are unaudited, and certain information and note disclosures normally included in the annual Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2010 Annual Reports on Form 10-K. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.

GAAP defines subsequent events as events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events as required by GAAP.

Principles of Consolidation

The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. 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

PNM declared a cash dividend to PNMR of $4.6 million in March 2011, which was paid in April 2011. TNMP declared and paid cash dividends to PNMR of $2.9 million in the three months ended March 31, 2011. The TNMP dividend was recorded as a reduction of its paid-in-capital. PNM and TNMP declared no dividends in the three months ended March 31, 2010. PNM also declared a cash dividend to PNMR of $39.1 million in December 2010 that was paid in January 2011.

27

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(2) Variable Interest Entities

On January 1, 2010, the Company adopted an amendment to GAAP that changes how an enterprise evaluates and accounts for its involvement with variable interest entities. This amendment modifies the determination of 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. The amendment also requires continual reassessment of the primary beneficiary of a variable interest entity and increases disclosure requirements. The adoption of this amendment did not change how the Company accounts for its existing arrangements with variable interest entities and the disclosures presented below reflect the requirements of the amendment.

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 ended March 31, 2011 and 2010, PNM paid $4.6 million and $4.1 million for fixed charges and $0.1 million and less than $0.1 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
	March 31,
	2011				2010
	(In thousands)
Operating revenues		$	4,670			$	4,502
Operating expenses			(1,487	)			(1,399	)
Earnings attributable to non-controlling interest		$	3,183			$	3,103

28

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Financial Position

	March 31, 2011			December 31, 2010
	(In thousands)
Current assets		$	2,702		$	2,372
Net property, plant and equipment			82,908			83,617
Total assets			85,610			85,989
Current liabilities			1,182			812
Owners’ equity – non-controlling interest		$	84,428		$	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 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 March 31, 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 $11.8 million and $26.0 million at March 31, 2011 and December 31, 2010 and 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, as well as through 2047 for Unit 3; 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

29

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

potential benefit from its renewal options, the vast majority of the value at the end of the leases will accrue to the beneficial owners of the trusts, particularly given increases in the value of existing nuclear generating facilities, which emit no GHG, resulting from anticipated carbon legislation or regulation.

PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. This arrangement was entered into prior to December 31, 2003 and PNM has been unsuccessful in obtaining the information necessary to determine if it is the primary beneficiary of the entity that owns Delta, or to consolidate that entity if it were determined that PNM is the primary beneficiary. Accordingly, PNM is unable to make those determinations and, as provided in GAAP, continues to account for this PPA as an operating lease. PNM makes fixed and variable payments to Delta under the PPA. PNM also controls the dispatch of the generating plant, which impacts the variable payments made under the PPA and impacts the economic performance of the entity that owns Delta. For the three months ended March 31, 2011 and 2010, PNM incurred fixed payments of $1.5 million and $1.4 million and variable payments of $0.2 million and less than $0.1 million under the PPA. PNM’s only quantifiable obligation under the PPA is to make the fixed payments, which as of March 31, 2011, aggregated $55.6 million through the end of the PPA in 2020. PNM will also pay variable costs, which cannot be quantified since the amounts are based on how much the generating plant is in operation. PNM has no other obligations or commitments with respect to Delta.

(3) Segment Information

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

PNM Electric

PNM Electric includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM Electric provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico 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. See Note 11.

Corporate and Other

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

30

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

PNMR SEGMENT INFORMATION

	PNM Electric				TNMP Electric				First Choice				Corporate and Other				Consolidated
Three Months Ended March 31, 2011	(In thousands)
Operating revenues		$	234,238			$	45,028			$	108,450			$	(53	)		$	387,663
Intersegment revenues			-				8,814				-				(8,814	)			-
Total revenues			234,238				53,842				108,450				(8,867	)			387,663
Cost of energy			89,214				10,153				67,954				(8,814	)			158,507
Gross margin			145,024				43,689				40,496				(53	)			229,156
Other operating expenses			103,124				19,703				18,987				(3,351	)			138,463
Depreciation and amortization			23,735				10,262				280				4,196				38,473
Operating income (loss)			18,165				13,724				21,229				(898	)			52,220
Interest income			4,057				-				4				(33	)			4,028
Other income (deductions)			5,217				316				(106	)			(1,602	)			3,825
Net interest charges			(18,080	)			(7,299	)			(146	)			(5,090	)			(30,615	)
Segment earnings (loss) before income taxes			9,359				6,741				20,981				(7,623	)			29,458
Income taxes (benefit)			2,395				2,578				7,492				(2,959	)			9,506
Segment earnings (loss) from continuing operations			6,964				4,163				13,489				(4,664	)			19,952
Valencia non-controlling interest			(3,183	)			-				-				-				(3,183	)
Subsidiary preferred stock dividends			(132	)			-				-				-				(132	)
Segment earnings (loss) from continuing operations attributable to PNMR		$	3,649			$	4,163			$	13,489			$	(4,664	)		$	16,637
At March 31, 2011:
Total Assets		$	3,866,571			$	1,011,252			$	215,457			$	120,446			$	5,213,726
Goodwill		$	51,632			$	226,665			$	43,013			$	-			$	321,310

31

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	PNM Electric				TNMP Electric				First Choice				Corporate and Other				Consolidated
Three Months Ended March 31, 2010	(In thousands)
Operating revenues		$	230,536			$	38,591			$	114,390			$	(60	)		$	383,457
Intersegment revenues			-				9,586				-				(9,586	)			-
Total revenues			230,536				48,177				114,390				(9,646	)			383,457
Cost of energy			86,434				9,051				104,990				(9,587	)			190,888
Gross margin			144,102				39,126				9,400				(59	)			192,569
Other operating expenses			108,793				18,789				20,448				(3,283	)			144,747
Depreciation and amortization			22,852				10,095				263				4,069				37,279
Operating income (loss)			12,457				10,242				(11,311	)			(845	)			10,543
Interest income			4,935				-				2				90				5,027
Equity in net earnings (loss) of Optim Energy			-				-				-				(4,352	)			(4,352	)
Other income (deductions)			11,157				346				(8	)			(1,456	)			10,039
Net interest charges			(18,077	)			(7,869	)			(311	)			(5,153	)			(31,410	)
Segment earnings (loss) before income taxes			10,472				2,719				(11,628	)			(11,716	)			(10,153	)
Income taxes (benefit)			2,921				1,075				(4,175	)			(4,760	)			(4,939	)
Segment earnings (loss) from continuing operations			7,551				1,644				(7,453	)			(6,956	)			(5,214	)
Valencia non-controlling interest			(3,103	)			-				-				-				(3,103	)
Subsidiary preferred stock dividends			(132	)			-				-				-				(132	)
Segment earnings (loss) from continuing operations attributable to PNMR		$	4,316			$	1,644			$	(7,453	)		$	(6,956	)		$	(8,449	)
At March 31, 2010:
Total Assets		$	3,843,558			$	1,006,747			$	232,864			$	377,221			$	5,460,390
Goodwill		$	51,632			$	226,665			$	43,013			$	-			$	321,310

32

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(4) 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.

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 would 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 the net open contract position were required to be covered as a result of the aforementioned 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 for the normal sales and purchases exception or for which the normal sales and purchases exception is not elected 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. Derivatives that meet the normal sales and purchases exception are not marked to market but rather recorded in results of operations when the underlying transactions settle.

33

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 March 31, 2011, after-tax losses of $0.2 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 March 31, 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 March 31, 2011 and December 31, 2010, amounts recognized for the legal right to reclaim cash collateral were $3.8 million and $3.4 million for PNMR and $3.0 million and $3.0 million for PNM. In addition, at March 31, 2011 and December 31, 2010, amounts posted as cash collateral under margin arrangements were $25.7 million and $32.0 million for PNMR and $1.8 million and $2.1 million for PNM. PNMR and PNM had no obligations to return cash collateral at March 31, 2011 and December 31, 2010. Cash collateral amounts are included in other current assets on the Condensed Consolidated Balance Sheets.

34

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Commodity Derivatives

Commodity derivative instruments are summarized as follows:

	PNMR Economic Hedges								PNM Economic Hedges
	March 31, 2011				December 31, 2010				March 31, 2011				December  31, 2010
	(In thousands)
Current assets		$	17,833			$	15,999			$	2,245			$	1,443
Deferred charges			6,247				5,264				7				-
			24,080				21,263				2,252				1,443
Current liabilities			(25,520	)			(31,407	)			(2,434	)			(3,110	)
Long-term liabilities			(10,567	)			(12,831	)			(1,560	)			(2,009	)
			(36,087	)			(44,238	)			(3,994	)			(5,119	)
Net		$	(12,007	)		$	(22,975	)		$	(1,742	)		$	(3,676	)

The Company had no trading or designated cash flow hedge transactions at March 31, 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 $0.6 million of current assets and less than $0.1 million of long-term liabilities at March 31, 2011 and $0.6 million of current assets at December 31, 2010 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.

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

	Economic Hedges							Trading Transactions						Qualified Cash Flow Hedges
	Three Months Ended March  31,							Three Months Ended March  31,						Three Months Ended March  31,
	2011			2010				2011			2010			2011				2010
	(In thousands)
PNMR
Electric operating revenues		$	1,144		$	(1,886	)		$	-		$	3		$	-			$	6,749
Cost of energy			4,680			(31,949	)			-			-			68				(477	)
Total gain (loss)		$	5,824		$	(33,385	)		$	-		$	3		$	68			$	6,272
Recognized in OCI															$	(68	)		$	765
PNM
Electric operating revenues		$	1,144		$	(1,886	)		$	-		$	-		$	-			$	6,749
Cost of energy			443			(3,625	)			-			-			-				55
Total gain (loss)		$	1,587		$	(5,511	)		$	-		$	-		$	-			$	6,804
Recognized in OCI															$	-			$	233

35

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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
March 31, 2011
PNMR		20,814,000		1,635,150
PNM		1,729,000		(1,521,202	)
December 31, 2010
PNMR		22,767,500		1,693,431
PNM		1,882,500		(990,120	)

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

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

Contingent Feature – Credit Rating Downgrade	Contractual Liability			Existing Cash Collateral			Net Exposure
	(In thousands)
March 31, 2011
PNMR		$	8,515		$	500		$	762
PNM		$	382		$	-		$	14
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

36

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table. PNMR and PNM do not have any unrealized losses on available-for-sale securities.

	March 31, 2011						December 31, 2010
	Unrealized Gains			Fair Value			Unrealized Gains			Fair Value
	(In thousands)
Equity securities:
Domestic value		$	6,865		$	27,848		$	5,108		$	25,491
Domestic growth			21,838			55,035			17,239			48,237
Global, all-cap			44			13,717			2,730			10,670
Fixed income securities:
Municipals			802			37,600			837			37,595
U.S. Government			242			21,259			348			21,541
Corporate and other			537			8,699			573			8,402
Cash investments			-			2,979			-			4,986
		$	30,328		$	167,137		$	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 March 31,
	2011				2010
	(In thousands)
Proceeds from sales		$	48,120			$	20,699
Gross realized gains		$	4,790			$	1,905
Gross realized (losses)		$	(1,728	)		$	(1,362	)

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

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

37

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At March 31, 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		$	2,504		$	-		$	-
After 1 year through 5 years			17,227			141,390			130,470
After 5 years through 10 years			11,313			3,207			-
Over 10 years			36,514			-			-
		$	67,558		$	144,597		$	130,470

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

	March 31, 2011						December 31, 2010
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	(In thousands)
PNMR
Long-term debt		$	1,566,008		$	1,677,817		$	1,565,847		$	1,659,674
Investment in PVNGS lessor notes		$	124,869		$	125,377		$	136,145		$	141,663
Other investments		$	17,925		$	21,911		$	18,791		$	21,675
PNM
Long-term debt		$	1,055,752		$	1,065,623		$	1,055,748		$	1,056,864
Investment in PVNGS lessor notes		$	124,869		$	125,377		$	136,145		$	141,663
Other investments		$	5,211		$	5,734		$	5,068		$	5,563
TNMP
Long-term debt		$	310,494		$	388,141		$	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

38

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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:

	Total(1)				Quoted Prices in Active Market for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
March 31, 2011	(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents		$	2,979			$	2,979			$	-			$	-
Equity securities:
Domestic value			27,848				27,848				-				-
Domestic growth			55,035				55,035				-				-
Global, all-cap			13,717				13,717				-				-
Fixed income securities:
U.S. government			21,259				16,374				4,885				-
Municipals			37,600				-				37,600				-
Corporate and other			8,699				-				8,699				-
Total NDT investments		$	167,137			$	115,953			$	51,184			$	-
PNMR
Commodity derivative assets		$	24,080			$	7,322			$	14,713			$	1,531
Commodity derivative liabilities			(36,087	)			(20,546	)			(14,390	)			(637	)
Net		$	(12,007	)		$	(13,224	)		$	323			$	894
PNM
Commodity derivative assets		$	2,252			$	-			$	2,252			$	-
Commodity derivative liabilities			(3,994	)			-				(3,994	)			-
Net		$	(1,742	)		$	-			$	(1,742	)		$	-

39

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	Total(1)				Quoted Prices in Active Market for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (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				-				-
International and other			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 March 31, 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 ended March 31, 2011 and 2010.

40

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

	PNMR								PNM
	Three Months Ended March  31,								Three Months Ended March  31,
	2011				2010				2011			2010
					(In thousands)
Balance at beginning of period		$	(822	)		$	248			$	-		$	(17	)
Total gains (losses) included in earnings			1,550				(377	)			-			(128	)
Purchases			118				-				-			-
Settlements			48				214				-			145
Balance at end of period		$	894			$	85			$	-		$	-
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		$	1,716			$	(180	)		$	-		$	-

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

	PNMR							PNM
	Three Months Ended March  31,							Three Months Ended March  31,
	2011			2010				2011			2010
						(In thousands)
Gains (losses) included in earnings:
Electric operating revenues		$	-		$	-			$	-		$	-
Cost of energy			1,550			(377	)			-			(128	)
Total		$	1,550		$	(377	)		$	-		$	(128	)
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues		$	-		$	-			$	-		$	-
Cost of energy			1,716			(180	)			-			-
Total		$	1,716		$	(180	)		$	-		$	-

41

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(5) Earnings Per Share

In accordance with GAAP, dual presentation of basic and diluted earnings (loss) per share has been presented in the Condensed Consolidated Statements of Earnings (Loss) of PNMR. Information regarding the computation of earnings (loss) per share is as follows:

	Three Months Ended March  31,
	2011			2010
	(In thousands, except per share amounts)
Net Earnings (Loss) Attributable to PNMR		$	16,637		$	(8,449	)
Average Number of Common Shares:
Outstanding during period			86,673			86,673
Equivalents from convertible preferred stock (Note 7)			4,778			4,778
Vested awards of restricted stock			182			95
Average Shares - Basic			91,633			91,546
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock			475			-
Average Shares - Diluted			92,108			91,546
Net Earnings (Loss) Per Share of Common Stock:
Basic		$	0.18		$	(0.09	)
Diluted		$	0.18		$	(0.09	)

⁽¹⁾  Excludes the effect of out-of-the-money options for 2,023,995 shares of common stock at March 31, 2011. Due to losses in the three months ended March 31, 2010, no potentially dilutive securities are reflected in the average number of common shares used to compute earnings (loss) per share since any impact would be anti-dilutive.

(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.

42

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Stock Options

The following table summarizes activity in stock option plans for the three months ended March 31, 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		(112,593	)		$	10.94
Forfeited		(8,333	)		$	11.33
Expired		(24,451	)		$	25.92
Outstanding at end of period		3,802,885			$	18.52		$	7,023,680	(1)		5.62 years
Exercisable at end of period		3,245,128			$	21.70		$	4,831,056			5.12 years
Options available for future grant(2)		4,783,531

⁽¹⁾  At March 31, 2011, the exercise price of 2,023,995 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:

	Three Months Ended March  31,
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)		$	1,179		$	1,022
Total intrinsic value of options exercised (in thousands)		$	396		$	159

Restricted Stock and Performance Shares

The following table summarizes nonvested restricted stock activity for the three months ended March 31, 2011:

Nonvested Restricted Stock	Shares			Weighted- Average Grant-Date Fair Value
Nonvested at beginning of period		237,021			$	9.24
Granted		277,773			$	12.90
Vested		(81,911	)		$	9.26
Forfeited		-			$	-
Nonvested at end of period		432,883			$	11.59

43

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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:

	Three Months Ended March  31,
Nonvested Restricted Stock	2011				2010
Weighted-average grant date fair value of shares granted		$	12.90			$	8.68
Total fair value of shares that vested (in thousands)		$	758			$	897
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 March 31, 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 2011. 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 March 31, 2011, the weighted average interest rate was 1.51% for the PNMR Facility and 0.90% for the PNM Facility. Short-term debt outstanding consists of:

	March 31,			December 31,
Short-term Debt	2011			2010
	(In thousands)
PNM – Revolving credit facility		$	212,000		$	190,000
TNMP – Revolving credit facility			-			-
PNMR
Revolving credit facility			12,000			32,000
Local lines of credit			-			-
		$	224,000		$	222,000

44

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At April 28, 2011, PNMR, PNM, and TNMP had $481.9 million, $94.8 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 April 28, 2011, on a consolidated basis, was $651.4 million for PNMR. At April 28, 2011, PNMR, PNM, and TNMP had no invested cash.

As of March 31, 2011, PNM had outstanding borrowings of $5.4 million from PNMR under its intercompany loan agreement. At April 28, 2011, PNM and TNMP had outstanding borrowings of $11.8 million and $8.0 million from PNMR under their intercompany loan agreements.

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 March 31, 2011 pre-tax fair value of $1.5 million is included in other current liabilities, except for $0.5 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 the 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.

45

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM Plans

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

	Three Months Ended March 31,
	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

PNM made contributions to its pension plan trust of $6.0 million and $6.5 million in the three months ended March 31, 2011 and 2010. PNM anticipates making $34.9 million of additional contributions in 2011. Based on current law and estimates of portfolio performance, PNM estimates making additional 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 made no contributions to the trust for other postretirement benefits for the three months ended March 31, 2011 and 2010. PNM expects to make contributions of $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 in the three months ended March 31, 2011 and 2010 and are expected to total $1.5 million during 2011.

TNMP Plans

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

	Three Months Ended March 31,
	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

TNMP made contributions to its pension plan trust of $0.1 million and zero in the three months ended March 31, 2011 and 2010. TNMP anticipates making additional contributions of $1.1 million in 2011. Based on current

46

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 made no contributions to the trust for other postretirement benefits for the three months ended March 31, 2011 and 2010. TNMP expects to make contributions of $0.4 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 less than $0.1 million in the three months ended March 31, 2011 and 2010 and are expected to total $0.1 million during 2011.

(9) Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company is also subject to federal, state, and local environmental laws and regulations, and is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. The Company is also involved in various legal proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal proceedings on its 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 $46.1 million (in 2007 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS. Such estimate does not consider the impact of the extension of the PVNGS operating

47

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 March 31, 2011 and December 31, 2010, PNM recorded interim storage costs of $15.0 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 SO₂ reduction milestones, which have been proposed but not yet finalized, are not met.

SJGS

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

As part of its 2007 submission, PNM analyzed SCR and concluded it was not appropriate as BART. PNM estimates 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. In its filing, the NMED stated that it did not necessarily agree with PNM’s estimate and that it expected the actual costs for SCR technology to be lower than PNM’s estimate. PNM estimates installation of the sorbent injection technology would be an additional cost of approximately $40 million for the entire station. These technologies would also increase operating costs at SJGS. NMED withdrew its petition for adoption of the regional haze SIP on December 17, 2010.

The EPA is subject to a consent decree that required it to issue a proposed FIP for certain states, including New Mexico, for regional haze mitigation by November 11, 2010, later extended to December 22, 2010, if no proposed SIP had been submitted. 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 does not require sorbent injection. The FIP provides 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 has been extended to August 5, 2011 pursuant to an agreement between EPA and WildEarth Guardians.

On February 28, 2011, the NMED filed a new petition with the EIB to consider two filings that comprise its draft interstate transport SIP and 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 the type of coal (sub-bituminous) and boiler configuration used at SJGS. 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 could take action to adopt the NMED SIP in early June upon conclusion of public hearings.

48

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM filed extensive technical and legal comments on the proposed FIP with the EPA, including a statement in support of the draft SIP. PNM is unable to predict whether the EPA will issue the final FIP in its current form or in a modified form or ultimately consider and adopt the February 2011 SIP. If the EPA issues a final rule that requires SCR technology, PNM will likely appeal the FIP in the court system. However, an appeal would not stop the implementation timeframe unless a court issued a stay. As stated above, PNM believes that SCR technology is not appropriate for BART at SJGS and that the recently installed pollution control equipment provides reasonable progress toward visibility improvements required under the EPA rules. In the event a final FIP is issued in the form of the proposed FIP, PNM believes that it would be extremely difficult to install SCR technology on all four units at SJGS within the three year timeframe. If a three year installation timeframe is ultimately required, PNM and the other owners of SJGS will have to evaluate their options, which could include shutting down part of SJGS during a portion of the installation process. No decisions have been made at this time and decisions can only be made after final rules are adopted and alternatives are analyzed.

PNM would 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 about $82 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 notice of intent 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 notice 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 notice of intent 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 such 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

49

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

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 extended the comment deadline for both the October 2010 proposal and the Supplemental Notice to May 2, 2011. APS is currently evaluating both proposals and will be providing comments to the EPA on both.

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. APS is currently evaluating the potential impact of this lawsuit.

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

50

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8-hour ozone standard by setting the standard in a range of 0.060-0.070 parts per million (“ppm”). EPA intends to establish a new ozone standard by July 31, 2011. If EPA sets the standard at 0.070 ppm, San Juan County may be designated as non-attainment for ozone. If the standard is set lower than 0.070 ppm, other counties in the state, including Bernalillo County, New Mexico, may be designated as non-attainment. A non-attainment designation for Bernalillo County could result in the requirement to reduce NOx emissions from Reeves Station by 2014, and a non-attainment designation for San Juan County could result in the requirement to reduce NOx emissions from SJGS by 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 quarter. As required by the Consent Decree, PNM submitted reports addressing mercury 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. An order from the court is pending. 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 (“VCA”) 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.

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

51

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. The Company 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 Notice of Intent to Sue from Earthjustice, on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at Four Corners. The notice 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.

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 Office of Surface Mining Reclamation and Enforcement (“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.

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 90 day public comment period, which ends on July 19, 2011, and 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.

52

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 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 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 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

53

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 the proper place for regulatory oversight 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 Notice of Intent to Sue (“RCRA Notice”) under the 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 notice of intent to sue under the Surface Mine Control and Reclamation Act (“SMCRA”) from the Sierra Club. On April 8, 2010, the Sierra Club filed suit in the U.S. District Court for the District of New Mexico against PNM, PNMR, SJCC, and BHP. In the suit, the Sierra Club alleges that activities at SJGS and the San Juan Mine are causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCBs at the San Juan Mine constitutes “open dumping” in violation of RCRA. The claims under RCRA are asserted with respect to PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA, which are directed only against SJCC and BHP. The complaint requests judgment for the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCBs at the mine or to cease placement of CCBs at the mine; the imposition of civil penalties; and an award of plaintiff’s attorney’s fees and costs. On July 10, 2010, the Sierra Club filed an amended complaint that corrected some technical deficiencies in its original complaint. The factual allegations remained the same. The parties have agreed to a stay of the action, which the Court entered on August 27, 2010, to allow the parties to try to address Sierra Club’s concerns. If the parties are unable to settle the matter, PNM is prepared to aggressively defend its position in the RCRA litigation. PNM and PNMR cannot predict the outcome of this matter 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 March 31, 2011 and December 31, 2010, prepayments for coal, which are included in other current assets, amounted to $29.4 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

54

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

the 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 48 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. APS is currently in discussions with the coal supplier regarding post-2016 coal supply for Four Corners.

In 2009, PNM completed a comprehensive review of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal. Based on this study, PNM revised its estimates of the final reclamation costs. In 2010, this study was updated. In July 2010, the coal supply contract for Four Corners was restructured with pricing to be determined using an escalating base-price. 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 March 31, 2011, are estimated to be $55.7 million for the surface mines at both SJGS and Four Corners and $21.7 million for the underground mine at SJGS, in future dollars. During the three months ended March 31, 2011 and 2010, PNM made payments of $1.3 million and $0.9 million against the surface mine liability. As of March 31, 2011 and December 31, 2010, obligations of $25.0 million and $25.0 million for surface mine reclamation and $2.8 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.

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 of each retrospective assessment 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.

55

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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’s situation in the future, 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 reserved surface water rights. On March 30, 2009, President Obama signed legislation confirming the settlement with the Navajo Nation. The Company 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. The Company is unable to predict the ultimate outcome of this matter. 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.

56

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

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 only in its initial stages, PNM cannot predict the outcome of the proceeding at this time.

Transmission Issues

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

57

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 are 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 and they remain pending further decision. 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.

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. 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,

58

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

the 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, as amended, 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, up to a maximum cost of $107.7 million, PNM’s estimated amounts of these investments, and a distributed generation REC purchase program. 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 2 MW of solar PV is in service, 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. The NMPRC ordered that the 180-day period for NMPRC action on the 2011 plan would start on the date the new plan was filed. On December 6, 2010, PNM filed a revised 2011 plan that proposes procurement of 423,860 MWh of wind generated RECs 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, requests a variance from the diversity requirements for solar and certain “other resources” for 2011 because of cost and availability constraints. A public hearing on the plan was held in April 2011. PNM cannot predict the outcome of this matter.

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

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 pending 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

59

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. The Court denied the stay motion. Oral argument was held before the New Mexico Supreme Court in February 2011. PNM cannot predict the ultimate outcome of these appeals.

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.

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 programs offered, 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 is $32.9 million, which includes the 2010 programs adder discussed above. On February 11, 2011, the NMPRC staff filed testimony that the amount of the incentive adder authorized by the energy efficiency rule should be prospectively reduced to $0.002 per kWh and $4 per KW and that recovery of certain carrying charges on uncollected program costs should be disallowed for alleged noncompliance with NMPRC rules. On February 21, 2011, PNM filed rebuttal testimony disputing the staff’s contentions. In its rebuttal testimony, PNM accepted certain modifications to its plan that were proposed by other parties. The effect of these modifications resulted in a revised proposed recovery amount of $31.4 million. A public hearing was held in February 2011. A decision is expected in the spring of 2011. PNM is unable to predict the outcome of this proceeding.

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 its adder 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 rider necessary to make up the under-collected balance of $2.6 million. This under collection is associated with the previously approved programs and energy efficiency rider. 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 incurred costs and approved program costs, the NMPRC suspended the proposed adjusted rates for 180 days commencing on May 1, 2011. The NMPRC, in its suspension order, concludes that some of the program budgets exceeded the authorized amount and questions whether PNM should have requested budget increases for these programs, whether PNM should be denied recovery of any of the under collected amount and whether any sanctions should be imposed. 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.

60

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

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 represents a 22% increase for PNM North and a 20% increase for PNM South. The filed revenue requirements are based on a future test period ending December 31, 2011. If the NMPRC grants the entire relief requested, PNM proposed to implement the increase in two steps. Phase 1 would become effective April 1, 2011 (PNM North: $111.1 million, 16%; PNM South: $8.7 million, 14%), and Phase 2 would 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 resolve all issues in the 2010 Electric Rate Case and provide a rate path for PNM through 2013. Other parties filed statements opposing the stipulation. This stipulation, which reflects some aspects of a future test year, is subject to approval of the NMPRC. The stipulation would allow 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 are 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 recover the costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning July 1, 2012 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 can 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 limits the amount that

61

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

can 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 these limits will be deferred for collection, without carrying costs, to future periods. If the stipulation is 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 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 is 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 and PNM has filed rebuttal testimony. The Hearing Examiner has established a procedural schedule that includes a hearing on the stipulation beginning on May 9, 2011. PNM is unable to predict the outcome of this matter.

2011 Integrated Resource Plan

NMPRC rules require that New Mexico investor owned utilities file an IRP every three years. PNM has been holding public advisory group meetings, and is planning on filing its 2011 IRP in July 2011. 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. The rule also requires that utilities conduct a public advisory group process during the development of the IRP. 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 to become effective June 1, 2011, subject to refund, and providing a schedule to establish hearing and settlement judge procedures, including a settlement conference on May 3, 2011. 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 have made a series of appeals on the ruling and it is currently before the Texas Supreme Court. TNMP is unable to predict if the Texas Supreme Court will review the decision or 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

62

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. The Court took the matter under advisement and consideration. While there is inherent uncertainty in this type of proceeding, TNMP believes it will ultimately be successful in overturning any ruling that the effective date should be prior to December 27, 2007.

Advanced Meter System Deployment and Surcharge Request

On May 26, 2010, TNMP filed a request with PUCT to approve TNMP’s proposed advanced meter deployment. The filing also requested a surcharge to collect $158 million in costs over 12 years, including recovery of capital expenditures of $70.6 million. On June 1, 2010, the PUCT referred the matter to the State Office of Administrative Hearings. On January 6, 2011, the ALJ modified the procedural schedule and set this matter for hearing on April 18, 2011. Due to changes in the tax law, TNMP filed supplemental testimony on February 16, 2011 to reflect the effects of the bonus depreciation, new WACC, and other changes. The filing amends the requested surcharge to collect $126 million, including capital expenditures of $70.2 million incurred through 2015. The ALJ has approved a revised schedule and reset the hearing for May 18-20, 2011.

2010 Rate Case

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

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 wherein TNMP would collect $2.8 million over the next three years. TNMP is unable to predict the outcome of this matter.

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 4^th 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 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

63

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 approximately $0.3 million due to the fact that its 2010 energy efficiency programs exceeded the performance goals set by the PUCT.

(11) Optim Energy

Information concerning Optim Energy is discussed in Note 22 of the 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, recently 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 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.

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. Discussions regarding various alternatives have been held with several potential parties and discussions with additional parties are possible. Although PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources as of the date of this report, based on the exploration of these alternatives to date, it is possible that PNMR may decide to contribute equity and/or other operational assets to Optim Energy or a new venture in order to consummate a strategic transaction. Depending on the form and structure of a strategic transaction, if any, as well as market conditions at the time the strategic transaction is consummated, PNMR may recognize additional impairments based on relative fair values. No assurances can be given that PNMR will consummate any strategic transaction with respect to its investment in Optim Energy.

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.

64

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Summarized financial information for Optim Energy is as follows:

Results of Operations

	Three Months Ended March 31,
	2011				2010
	(In thousands)
Operating revenues		$	73,933			$	105,593
Cost of energy			57,967				77,297
Gross margin			15,966				28,296
Non-fuel operations and maintenance expenses			9,243				10,520
Administrative and general expenses			6,937				5,612
Depreciation and amortization expense			11,613				12,057
Taxes other than income tax			2,370				3,433
Operating income (loss)			(14,197	)			(3,326	)
Interest charges			(3,984	)			(4,671	)
Other income (deductions)			68				65
Earnings (loss) before income taxes			(18,113	)			(7,932	)
Income taxes (benefit)(1)			47				32
Net earnings (loss)		$	(18,160	)		$	(7,964	)
50 percent of net earnings (loss)		$	(9,080	)		$	(3,982	)
Amortization of basis difference in Optim Energy			-				(370	)
Post-impairment loss not recorded under GAAP			9,080				-
PNMR equity in net earnings (loss) of Optim Energy		$	-			$	(4,352	)

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

Financial Position

	March 31, 2011				December 31, 2010
	(In thousands)
Current assets		$	102,282			$	105,413
Net property plant and equipment			918,889				924,354
Other long-term assets			115,554				120,894
Total assets			1,136,725				1,150,661
Current liabilities			52,804				50,226
Long-term debt			717,000				717,000
Other long-term liabilities			9,115				7,515
Total liabilities			778,919				774,741
Owners’ equity		$	357,806			$	375,920
50 percent of owners’ equity		$	178,903			$	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			9,080				-
PNMR equity investment in Optim Energy		$	-			$	-

65

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. During the three months ended March 31, 2011 and 2010, Optim Energy recorded amortization of contracts acquired of $3.7 million and $4.0 million, which decreased operating revenues, and amortization expense on emission allowances of $2.5 million and $1.3 million, which increased 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 March 31, 2011, all other transactions are designated as economic hedges that are required to be marked to market.

(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 the Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

66

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 March 31,
	2011			2010
	(In thousands)
Electricity, transmission and distribution related services billings:
TNMP to PNMR		$	8,814		$	9,586
Services billings:
PNMR to PNM			21,437			21,662
PNMR to TNMP			6,581			6,488
PNM to TNMP			122			100
TNMP to PNMR			53			121
PNMR to Optim Energy			1,400			1,438
Optim Energy to PNMR			11			18
Interest charges:
TNMP to PNMR			2			83
PNM to PNMR			28			3
PNMR to PNM			32			-

(13) Jointly-Owned Electric Generating Plants

Information concerning Jointly-Owned Electric Generating Plants is discussed in Note 14 of the 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.

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.

67

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 continued 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 represents a 22% increase for PNM North and 20% increase for PNM South. The filed revenue requirements are 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 resolve all issues in the 2010 Electric Rate Case and provide a rate path for PNM through 2013. Other parties filed statements opposing the stipulation. This stipulation, which reflects some aspects of a future test year, is subject to approval of the NMPRC. The stipulation would allow 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 are 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 recover the costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning July 1, 2012 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 can 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 limits the amount that can 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 these limits will be deferred for collection, without carrying costs, to future periods. If the stipulation is 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 and PNM has filed rebuttal

68

testimony. The Hearing Examiner has established a procedural schedule that includes a hearing on the stipulation beginning on May 9, 2011. See Note 10. PNM is unable to predict the outcome of this proceeding.

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 to become effective June 1, 2011, subject to refund, and providing a schedule to establish hearing and settlement judge procedures, including a settlement conference on May 3, 2011. 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 stipulation in the 2010 Electric Rate Case discussed above would, if approved by the NMPRC, provide for a rate increase to the former TNMP customers on the same percentage basis as PNM’s other customers. In April 2011, the NMPRC issued an order that consolidated this case with the pending 2010 Electric Rate Case. See Note 10.

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. 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 is $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.

69

Competitive Businesses

First Choice

As a REP, First Choice operates in the highly competitive Texas retail market, which has experienced extreme price volatility and transmission congestion in the past. ERCOT controls the transmission of power in the areas that First Choice supplies. ERCOT historically has operated through a series of geographic zones, which has led to congestion of the transmission system when large volumes of power were being transmitted between zones. Congestion tends to drive prices up in the spot market. These anomalies also negatively impacted the margins realized from end use customers. 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 becomes effective on June 1, 2011.

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, however, Optim Energy was affected by continuing adverse market conditions, primarily low natural gas and power prices. The adverse market conditions continued throughout 2010. 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, recently reported sales of electric generating resources within the ERCOT market have been transacted at prices (per KW of generating capacity) that are 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 discussions regarding strategic alternatives for Optim Energy discussed in 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

70

ownership interest in Optim Energy. Discussions regarding various alternatives have been held with several potential parties and discussions with additional parties are possible. Although PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources as of the date of this report, based on the exploration of these alternatives to date, it is possible that PNMR may decide to contribute equity and/or other operational assets to Optim Energy or a new venture in order to consummate a strategic transaction. Depending on the form and structure of a strategic transaction, if any, as well as market conditions at the time the strategic transaction is consummated, PNMR may recognize gains or additional impairments based on relative fair values. No assurances can be given that PNMR will consummate any strategic transaction with respect to its investment in Optim Energy.

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.

71

RESULTS OF OPERATIONS

Executive Summary

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

	Three Months Ended March 31,
	2011		2010		Change
	(In millions, except per share amounts)
Net earnings (loss)		$  16.6		$    (8.4)		$  25.1
Average common and common equivalent shares outstanding		92.1		91.5		0.6
Net earnings (loss) per diluted share		$  0.18		$  (0.09)		$  0.27

The components of the change in earnings (loss) attributable to PNMR (in millions) are:

PNM Electric	$  (0.7)
TNMP Electric	2.5
First Choice	20.9
Corporate and Other	(0.3)
Optim Energy	2.6
Net change	$  25.1

Detailed information regarding the changes in earnings (loss) is included in the segment information below. The after-tax changes relate primarily to mark-to-market gains on unrealized economic hedges at First Choice, which increased earnings by $5.9 million in 2011 compared to a decrease in earnings of $17.9 million in 2010. In addition, revenues and margins at TNMP increased by $1.8 million due to the implementation of a $10.25 million base rate increase beginning February 1, 2011. 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.

72

PNM Electric

The table below summarizes operating results for PNM Electric:

	Three Months Ended March 31,
	2011		2010		Change
	(In millions)
Total revenues		$  234.2		$  230.5		$    3.7
Cost of energy		89.2		86.4		2.8
Gross margin		145.0		144.1		0.9
Operating expenses		103.1		108.8		(5.7)
Depreciation and amortization		23.7		22.9		0.9
Operating income		18.2		12.5		5.7
Other income (deductions)		9.3		16.1		(6.8)
Net interest charges		(18.1)		(18.1)		-
Earnings before income taxes		9.4		10.5		(1.1)
Income (taxes)		(2.4)		(2.9)		0.5
Valencia non-controlling interest		(3.2)		(3.1)		(0.1)
Preferred stock dividend requirements		(0.1)		(0.1)		-
Segment earnings		$      3.6		$      4.3		$  (0.7)

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

		0000000		0000000		0000000
	2011/2010 Change
	Total Revenues		Cost of Energy		Gross Margin
	(In millions)
Retail rate increases		$  3.1		$      -		$  3.1
Retail load, fuel and transmission		6.5		6.3		0.2
Unregulated margins		(9.3)		0.4		(9.7)
Net unrealized economic hedges		3.3		(3.9)		7.2
Total increase (decrease)		$  3.7		$  2.8		$  0.9

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

	Three Months Ended March 31,
	2011		2010		Change
	(In millions, except customers)
Residential		$    88.2		$    84.4		$    3.8
Commercial		76.9		72.9		4.0
Industrial		20.7		20.3		0.4
Public authority		4.8		4.4		0.4
Other retail		2.1		2.1		-
Transmission		10.1		9.7		0.4
Firm requirements wholesale		9.6		8.2		1.4
Other sales for resale		20.5		30.6		(10.1)
Mark-to-market activity		1.3		(2.1)		3.4
		$  234.2		$  230.5		$    3.7
Average retail customers (thousands)		503.6		501.0		2.6

73

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

		00000		00000		00000
	Three Months Ended March 31,
	2011		2010		Change
	(Gigawatt hours)
Residential		851.9		858.4		(6.5)
Commercial		891.9		881.2		10.7
Industrial		361.4		349.8		11.6
Public authority		57.4		54.2		3.2
Firm requirements wholesale		183.3		177.2		6.1
Other sales for resale		610.6		541.2		69.4
		2,956.5		2,862.0		94.5

Retail revenues and margins increased $3.9 million in the first quarter of 2011 due to the second phase of a $27.0 million base rate increase implemented April 1, 2010 and higher retail loads due to an increase in the number of retail customers. These increases were more than offset by the reduction in revenues and margins of $9.7 million associated with sales from PNM’s share of PVNGS Unit 3, which is excluded from retail regulation. 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, resulting in decreased revenues and margin.

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 $1.9 million for the first quarter of 2011 compared to unrealized losses of $5.3 million in the first quarter of 2010, increased gross margin by $7.2 million.

Lower operating expenses are driven by reduced maintenance costs incurred at generation facilities in 2011 compared to 2010. Energy production cost decreased in the first quarter of 2011 due to improved plant performance at SJGS in 2011 and the timing of a major outage at Four Corners in 2010. In addition, lower labor and incentive compensation costs in the first quarter of 2011 further reduced operating expenses. These reductions are partially offset by increases in expenses for recently renewed transmission rights-of-way agreements and higher property taxes due to increases in investment in transmission and distribution assets.

Depreciation and amortization costs increased as a result of increased plant assets, primarily associated with transmission and distribution investment.

Other income is lower in 2011 due to an $8.5 million settlement associated with the Republic Savings Bank litigation received in the first quarter of 2010, which did not recur in 2011. Other income increased by $4.1 million due to improved performance of the NDT assets, offset by $1.0 million in lower capitalization for the equity portion of AFUDC, and $0.8 million in lower interest income on the PVNGS Lessor Notes due to a lower outstanding balance.

Lower interest rates on debt refinanced in the second quarter of 2010 reduced interest charges. These savings are offset by reductions in the capitalization of the debt portion of AFUDC due to lower capitalization rates.

PNM is a participant in PVNGS and is entitled to 10.2% of the plant’s capacity and energy. On April 21, 2011, the NRC issued 20 year extensions to the operating licenses for each of the three units at PVNGS. PNM is currently analyzing the impacts of the license extensions.

74

TNMP Electric

The table below summarizes the operating results for TNMP Electric:

		0000000		0000000		0000000
	Three Months Ended March 31,
	2011		2010		Change
	(In millions)
Total revenues		$  53.8		$  48.2		$  5.7
Cost of energy		10.2		9.1		1.1
Gross margin		43.7		39.1		4.6
Operating expenses		19.7		18.8		0.9
Depreciation and amortization		10.3		10.1		0.2
Operating income		13.7		10.2		3.5
Other income (deductions)		0.3		0.3		-
Net interest charges		(7.3)		(7.9)		0.6
Earnings before income taxes		6.7		2.7		4.0
Income (taxes)		(2.6)		(1.1)		(1.5)
Segment earnings		$    4.2		$    1.6		$  2.5

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

		0000000		0000000		0000000
	2011/2010 Change
	Total Revenues		Cost of Energy		Gross Margin
	(In millions)
Rate increases		$  2.8		$      -		$  2.8
Customer usage/load		0.4		-		0.4
Transmission cost recovery		2.0		1.1		0.9
Other		0.5		-		0.5
Total increase (decrease)		$  5.7		$  1.1		$  4.6

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

		0000000		0000000		0000000
	Three Months Ended March 31,
	2011		2010		Change
	(In millions, except customers)
Residential		$    19.5		$  18.9		$  0.6
Commercial		19.4		17.5		1.9
Industrial		3.2		3.0		0.2
Other		11.7		8.8		2.9
		$    53.8		$  48.2		$  5.6
Average customers (thousands) (1)		230.6		228.5		2.1

⁽¹⁾  Under TECA, customers of TNMP Electric in Texas have the ability to choose First Choice or any other REP to provide energy. The average customers reported above include 69,106 and 79,193 customers of TNMP Electric for the three months ended March 31, 2011 and 2010, who have chosen First Choice as their REP. These customers are also included in the First Choice segment.

75

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

	Three Months Ended March 31,
	2011		2010		Change
	(Gigawatt hours (1))
Residential		582.4		611.5		(29.1)
Commercial		506.6		476.4		30.2
Industrial		620.4		516.8		103.6
Other		25.5		24.8		0.7
		1,734.9		1,629.5		105.4

⁽¹⁾  The GWh sales reported above include 209.6 and 249.5 GWhs for the three months ended March 31, 2011 and 2010 used by customers of TNMP Electric, who have chosen First Choice as their REP. These GWhs are also included below in the First Choice segment.

Revenues and margins increased by $2.8 million associated with the implementation of a $10.25 million base rate increase beginning February 1, 2011 and a transmission rate increase in May 2010. In 2011, changes to Texas retail electric rules allow distribution providers to defer into a regulatory asset or liability the difference between wholesale transmission costs charged to the distribution provider and the revenues it charges its customers for these costs. Previously, distribution providers had no mechanism to capture these differences between its transmission cost recovery filings. Gross margins increased by $0.9 million in the first quarter of 2011 due to this mechanism. Retail revenues and margins increased by $0.4 million due to higher retail loads driven by cooler temperatures in the first quarter of 2011 and an increase in the number of retail customers.

Operating expenses increased in the first quarter of 2011 as a result of increased vegetation management costs and rate case expenses associated with the 2010 TNMP rate case that were determined to not be collectible from customers.

TNMP amended its revolving credit facility in December 2010, which extended its expiration to December 2015. The amendment resulted in more favorable interest rates, which reduced interest charges in the first quarter of 2011.

First Choice

The table below summarizes the operating results for First Choice:

		00000000		00000000		00000000
	Three Months Ended March 31,
	2011		2010		Change
	(In millions)
Total revenues		$  108.5		$  114.4		$  (5.9)
Cost of energy		68.0		105.0		(37.0)
Gross margin		40.5		9.4		31.1
Operating expenses		19.0		20.4		(1.5)
Depreciation and amortization		0.3		0.3		-
Operating income (loss)		21.2		(11.3)		32.5
Other income (deductions)		(0.1)		-		(0.1)
Net interest charges		(0.1)		(0.3)		0.2
Earnings (loss) before income taxes		21.0		(11.6)		32.6
Income (taxes) benefit		(7.5)		4.2		(11.7)
Segment earnings (loss)		$    13.5		$    (7.5)		$  20.9

76

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

		0000000		0000000		0000000
	2011/2010 Change
	Total Revenues		Cost of Energy		Gross Margin
	(In millions)
Weather		$  (1.8)		$    (1.2)		$  (0.6)
Customer growth/usage		5.5		3.6		1.9
Retail margins		(9.6)		(2.5)		(7.1)
Unrealized economic hedges		-		(36.9)		36.9
Total increase (decrease)		$  (5.9)		$  (37.0)		$   31.1

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

		0000000		0000000		0000000
	Three Months Ended March 31,
	2011		2010		Change
	(In millions, except customers)
Residential		$    63.6		$    74.7		$  (11.1)
Commercial		41.1		35.7		5.4
Other		3.8		4.0		(0.2)
		$  108.5		$  114.4		$    (5.9)
Actual customers (thousands) (1,2)		212.8		221.4		(8.6)

⁽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 at the end of the period are presented in the table above as a more representative business indicator than the average customers that are shown in the table for TNMP customers.

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

		000000		000000		000000
	Three Months Ended March 31,
	2011		2010		Change
	(Gigawatt hours) (1)
Residential		488.7		550.1		(61.4)
Commercial		369.1		279.8		89.3
		857.8		829.9		27.9

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

During 2011, a decrease in average revenue rates, unfavorable weather, and a reduction in the number of customers resulted in decreased operating revenue when compared to first quarter 2010. The decrease in 2011 was partially offset by lower purchase power costs and an increase in MWh sales but overall resulted 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 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. During the first quarter of 2011, market energy prices increased, which resulted in gains on certain of First Choice’s forward supply contracts. These gains were in contrast to the losses experienced in first quarter of 2010 when market energy prices significantly decreased. 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. First quarter gains on unrealized economic hedges increased segment earnings by $9.1 million in 2011 compared with losses of $27.8 million in 2010. These mark-to-market gains are not necessarily indicative of the amounts that will be realized upon settlement or the retail margin First Choice will realize.

77

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 in the first quarter of 2011, which increased segment earnings by $1.3 million. 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, an increase in marketing and operational costs was offset by a decrease in incentive compensation expense. The increase in operational costs was primarily related to developing a pre-pay option for customers 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:

		0000000		0000000		0000000
	Three Months Ended March 31,
	2011		2010		Change
	(In millions)
Total revenues		$  (8.9)		$  (9.6)		$  0.8
Cost of energy		(8.8)		(9.6)		0.8
Gross margin		(0.1)		(0.1)		-
Operating expenses		(3.4)		(3.3)		(0.1)
Depreciation and amortization		4.2		4.1		0.1
Operating income (loss)		(0.9)		(0.8)		(0.1)
Equity in net earnings (loss) of Optim Energy		-		(4.4)		4.4
Other income (deductions)		(1.6)		(1.4)		(0.3)
Net interest charges		(5.1)		(5.2)		0.1
Earnings (loss) before income taxes		(7.6)		(11.7)		4.1
Income (taxes) benefit		3.0		4.8		(1.8)
Segment earnings (loss)		$  (4.7)		$  (7.0)		$  2.3

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 to First Choice. Corporate and Other also includes equity in Optim Energy’s results of operations, which are further explained below.

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.

78

The table below summarizes the operating results for Optim Energy:

		00000000		00000000		00000000
	Three Months Ended March 31,
	2011		2010		Change
	(In millions)
Total operating revenues		$   73.9		$  105.6		$  (31.7)
Cost of energy		58.0		77.3		(19.3)
Gross margin		16.0		28.3		(12.3)
Operating expenses		18.6		19.5		(0.9)
Depreciation and amortization		11.6		12.1		(0.5)
Operating income (loss)		(14.2)		(3.3)		(10.9)
Other income (deductions)		0.1		0.1		-
Net interest charges		(4.0)		(4.7)		0.7
Earnings (loss) before income taxes		(18.1)		(7.9)		(10.2)
Income (tax) benefit on margin		-		-		-
Net earnings (loss)		$  (18.2)		$   (8.0)		$  (10.2)
50 percent of net earnings (loss)		$(9.1)		$(4.0)		$    (5.1)
Amortization of basis difference in Optim Energy		-		(0.4)		0.4
Post-impairment loss not recorded under GAAP		9.1		-		9.1
PNMR equity in net earnings (loss) of Optim Energy		$         -		$   (4.4)		$      4.4

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 March 31, 2011, all other transactions are designated as economic hedges that are required to be marked to market. On-going EBITDA excludes the forward mark-to-market losses of $3.2 million for 2011 and gains of $4.3 million for 2010.

Low power prices resulted in a decline in Optim Energy’s average realized power price in 2011. Optim Energy offset the decline through optimization of generation and increased ancillary revenues of $1.2 million in 2011 compared to 2010. Sales of excess emission allowances were $3.9 million greater in 2011 than 2010. Property tax reductions in mid-2010 decreased operating expenses $1.1 million from 2010 to 2011.

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 in 2011 and $4.0 million in 2010. Amortization for out of market contracts will continue through 2021. In addition, 2011 and 2010 cost of energy includes $2.5 million and $1.3 million of amortization related to emission allowances. The amortizations for emission allowances are recorded as the allowances are used in plant operations, sold, or expire.

On-going EBITDA excludes interest expense and depreciation. Declining interest rates, debt paydowns, and reductions in letters of credit reduced interest costs from $4.7 million in 2010 to $4.0 million in 2011. Depreciation expense decreased in the 2011 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

79

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. 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 three months ended March 31, 2011 compared to 2010 are summarized as follows:

	Three Months Ended March 31,
	2011		2010		Change
	(In millions)
Net cash flows from:
Operating activities		$  58.7		$  (13.3)		$    72.0
Investing activities		(48.9)		(54.1)		5.2
Financing activities		(12.3)		81.7		(94.0)
Net change in cash and cash equivalents		$  (2.5)		$   14.3		$  (16.8)

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 and $13.5 million related to the timing of collections under the FPPAC at PNM. In addition, decreases in posted collateral requirements of $5.7 million at PNM and $23.0 million at First Choice contributed to the change.

The changes in PNMR’s cash flows from investing activities relate primarily to payments for rights-of-way renewals of $16.0 million in 2010, partially offset by an $11.6 million increase in construction expenditures in 2011. Construction expenditures were funded primarily through short-term borrowings in 2010 and through excess cash flows from operating activities and short-term borrowings in 2011.

The changes in cash flows from financing activities primarily relate to a $88.0 million reduction in net short-term borrowings in 2011 compared to 2010. In addition, payments received on PVNGS firm-sales contract arrangements declined from $7.6 million in 2010 to $2.6 million in 2011 as those contracts expired on December 31, 2010.

Financing Activities

See Note 7 for information concerning the Company’s financing activities during the three months ended March 31, 2011. 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 March 31, 2011, for total capital requirements for 2011 are $415.8 million, including construction expenditures of $369.6 million. Total capital requirements for the years 2011-2015 are projected to be $1,617.4 million, including construction expenditures of $1,386.2 million. These amounts do not include forecasted construction expenditures of Optim Energy. These estimates are under continuing review and subject to on-going adjustment, as well as to Board review and approval.

80

During the three months ended March 31, 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.

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 zero to $32.0 million during the three months ended March 31, 2011. Borrowings under the PNM Facility ranged from $190.0 million to $231.0 million during the three months ended March 31, 2011. There have been no borrowings under the TNMP Revolving Credit Facility during 2011. At March 31, 2011, average interest rates were 1.51% for the PNMR Facility and 0.90% for the PNM Facility.

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 March 31, 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 2011. As of April 28, 2011, the Company had short-term debt outstanding of $259.1 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.

81

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 April 28, 2011 is as follows:

		000000000		000000000		000000000		000000000
	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 April 28, 2011:
Revolving credit facility		$    16.0		$  242.0		$        -		$     258.0
Local lines of credit		1.1		-		-		1.1
Total short-term debt outstanding		17.1		242.0		-		259.1
Letters of credit		48.0		49.2		0.3		97.5
Total short–term debt and letters of credit		$    65.1		$  291.2		$    0.3		$     356.6
Remaining availability as of April 28, 2011		$  481.9		$    94.8		$  74.7		$     651.4
Invested cash as of April 28, 2011		$          -		$          -		$        -		$             -

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.

For offerings of equity and debt securities registered with the SEC, PNMR has an effective 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. In 2008, PNM filed a shelf registration statement for the issuance of up to $600.0 million of senior unsecured notes that was scheduled to expire on April 29, 2011. On April 15, 2011, PNM filed a new shelf registration statement for the issuance of up to $600.0 million of senior unsecured notes. Until the latest registration statement is declared effective by the SEC, the SEC rules would allow PNM to continue to issue the remaining unissued securities registered from the prior shelf registration statement, which as of April 28, 2011 was $600.0 million.

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.

82

Off-Balance Sheet Arrangements

PNMR’s off-balance sheet arrangements include PNM’s operating lease obligations for PVNGS Units 1 and 2, the EIP transmission line, and Delta, a 132 MW gas-fired generating plant. These arrangements help ensure PNM the availability of lower-cost generation needed to serve customers. See MD&A – Off-Balance Sheet Arrangements and Note 7 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

Commitments and Contractual Obligations

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

Contingent Provisions of Certain Obligations

As discussed in the 2010 Annual Reports on Form 10-K, PNMR, PNM, and TNMP have a number of debt obligations and other contractual commitments that contain contingent provisions. Some of these, if triggered, could affect the liquidity of the Company. The contingent provisions include contractual increases in the interest rate charged on certain of the Company’s short-term debt obligations in the event of a downgrade in credit ratings and the requirement to provide security under certain contractual agreements. The Company believes its financing arrangements are sufficient to meet the requirements of the contingent provisions.

Capital Structure

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

		00000000000000		00000000000000
	March 31, 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		51.3%		51.3%
Preferred stock		0.5%		0.5%
Long-term debt		48.2%		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%

83

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 CO₂ emissions.

PNM has several programs underway to reduce GHG from its generation fleet, thereby reducing its exposure to climate change regulation. See Note 10. PNM is building 22 MW of utility-scale solar generation located at various sites on PNM’s system throughout New Mexico, the first 2 MW of which is in service and the rest will be complete by the end of 2011. On September 15, 2010, PNM filed requests for approval of an updated energy efficiency and load management plan with the NMPRC. A decision is expected in the spring of 2011. The new plan, if approved will improve the suite of energy efficiency programs PNM offers its customers. Over the next 19 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 12,600 GWh of electricity, which will avoid at least 6.1 million metric tons of CO₂ based upon projected emissions from PNM’s system-wide portfolio with and without these programs. These estimates are subject to change given that it is difficult to accurately estimate avoidance because of the many underlying variables with high uncertainty and complex interrelationships, including changes in demand for electricity.

Management periodically updates the Board on the matters discussed in this section and the Board regularly considers the issues around climate change, the Company’s GHG, and potential financial consequences that might result from potential federal and/or state regulation of GHG. PNM’s Board of Directors monitors Company practices and procedures to assess the sustainability impacts of our operations and products on the environment. This includes reviewing environmental management systems, monitoring the implementation of corporate environmental policy, monitoring the promotion of energy efficiency, and monitoring the use of renewable energy resources.

EPA Regulation

In April 2007, the U.S. Supreme Court held that 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 July 2008, the EPA published the Greenhouse Gas Advanced Notice of Proposed Rulemaking. The notice identified, but did not choose among, options for GHG regulation and requested comments on the options presented. Absent Congressional action, in due course the Company expects the EPA to adopt regulations relating to 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 emit 75,000 tons per year or more of GHGs and are currently subject to the PSD and Title V operating permit programs due to the amount of other regulated emissions. All of PNM’s existing generating plants are subject to the PSD and Title V programs because of the magnitude of non-GHG. Any modification at these facilities resulting in an increase of greater than or equal to 75,000 tons per year of GHG – a margin of 0.6 percent of SJGS’s 2010 emissions – would trigger PSD

84

permitting requirements, including a best available control technology (“BACT”) analysis for GHG. Phase 2 starts July 1, 2011 and addresses any large source of GHG that was not previously subject to the PSD and Title V regulatory programs. Phase 3, effective in July 2013, will phase in 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. The proposed NSPS regulations that will affect electric generating units are scheduled to be issued by July 26, 2011 and finalized by May 26, 2012. The Clean Air Act’s NSPS provisions include separate tracks 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 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 in September 2008 showed that incorporation of the NMPRC required carbon emissions costs did not significantly change the dispatch of existing facilities or 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 the dispatch of existing resources or future resource decisions. The primary consequence of the standardized cost of carbon emissions was an increase to

85

generation portfolio costs. The public involvement phase of PNM’s next IRP for the period 2011 to 2030 began in July 2010, and PNM is scheduled to file the plan by July 16, 2011.

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. 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 has appealed the EIB’s decision and the appeal is pending. If NMED 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. PNM has appealed the EIB’s decision and the appeal is pending. If the rule takes effect, PNM will seek to recover in rates any increased costs due to the rule.

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. PNM and other affected companies have filed appeals of the two rules with the New Mexico Court of Appeals. In addition, although the New Mexico 2010 legislative session did not repeal these rules, it is possible 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.

86

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 transmit, distribute, and/or generate energy, hurricanes can temporarily reduce customers’ usage and demand for energy.

Impact of Earthquake and Tsunami in Japan on Nuclear Energy Industry

On March 11, 2011, a 9.0 magnitude earthquake occurred off the north-eastern coast of Japan. The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Preliminary data available from the Fukushima Daiichi plant operator and Japanese government have each indicated that the earthquake and tsunami were beyond the plant’s required licensing and design parameters. Validation of that data will continue as more information becomes available.

The Nuclear Energy Institute (“NEI”) and the Institute of Nuclear Power Operations (“INPO”) are working closely to analyze the situation in Japan and develop action plans for U.S. nuclear power plants. APS, as operator of PVNGS, is actively engaged with NEI and INPO in these efforts. Additionally, the NRC is performing its own independent review of the events at Fukushima Daiichi. On March 23, 2011, the NRC Commissioners voted to launch a two-pronged review of U.S. nuclear power plant safety. The NRC announced that it supports the establishment of an agency task force that will conduct both short and long term analyses of the lessons that can be learned from the situation in Japan. The NRC expects the task force to begin its long-term evaluations within 90 days and anticipates that a report with any recommended actions will be available within six months after the evaluations begin.

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 March 31, 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.

87

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 its utilization of a future test year in its current electric rate filing with the NMPRC, including PNM’s ability to withstand challenges by regulators and intervenors, in the event the pending stipulation in that case is not approved,

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

• 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, including uncertainties surrounding PNMR’s assessment of strategic alternatives for its investment in Optim Energy, the risk that a strategic transaction involving Optim Energy may not be consummated, uncertainty regarding potential additional contributions to Optim Energy, and the possibility that PNMR might recognize additional gains or impairments depending on market conditions, the form and structure of a strategic transaction, and relative fair values,

88

• 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,

• 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,

• 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

89

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

90

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:

	Trading		Economic   Hedges		Total
Three Months Ended March 31, 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		-		5,178		5,178
Changes in fair value		-		5,824		5,824
Net change recorded as mark-to-market		-		11,002		11,002
Net change recorded as regulatory assets and liabilities		-		26		26
Unearned/prepaid option premiums		-		8		8
Settlement of de-designated cash flow hedges		-		(68)		(68)
Net fair value at end of period		$      -		$ (12,007)		$(12,007)

	Trading		Economic   Hedges		Total
Three Months Ended March 31, 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		(294)		771		477
Changes in fair value		3		(33,835)		(33,832)
Net change recorded as mark-to-market		(291)		(33,064)		(33,355)
Unearned/prepaid option premiums		-		1,618		1,618
Settlement of de-designated cash flow hedges		-		476		476
Net fair value at end of period		$   948		$ (28,753)		$ (27,805)

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. The following values were determined using broker quotes and option models:

Fair Value of Mark-to-Market Instruments at March 31, 2011

	Less than   1 year		1-3 Years		4+ Years		Total
			(In thousands)
Economic hedges
Prices actively quoted		$ (10,961)		$ (2,263)		$      -		$ (13,224)
Prices provided by other external sources		2,547		(1,764)		(460)		323
Prices based on models and other valuations		727		167		-		894
Total		$ (7,687)		$ (3,860)		$ (460)		$ (12,007)

91

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 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 gain or 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 three months ended March 31, 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 twelve 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 three months ended March 31, 2011, the average GEaR amount was $2.0 million, with high and low GEaR amounts for the period of $2.7 million and $1.3 million. The total GEaR amount at March 31, 2011 was $2.2 million. For the three months ended March 31, 2010, the average GEaR amount for these transactions was $3.1 million, with high and low GEaR amounts for the period of $4.4 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 $0.2 million at March 31, 2011. For the three months ended March 31, 2011, the high, low and average VaR amounts were $0.7 million, $0.1 million and $0.2 million. For the three months ended March 31, 2010, the high, low and average VaR amounts were $2.3 million, $0.4 million and $1.5 million.

92

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 three months ended March 31, 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.

The following table provides information related to PNMR’s credit exposure as of March 31, 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.

Schedule of Credit Risk Exposure

March 31, 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		$  11,605		3		$  4,897
Split ratings		15		-		-
Non-investment grade		22		-		-
Internal ratings:
Investment grade		57		-		-
Non-investment grade		338		-		-
Total		$  12,037				$  4,897

⁽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 March 31, 2011, PNMR held no credit collateral to offset its credit exposure.

93

The following table provides an indication of the maturity of PNMR’s credit risk by credit ratings of the counterparties.

Maturity of Credit Risk Exposure

March 31, 2011

Rating	Less than     2 Years		2-5 Years		Greater than      5 Years		Total Net      Exposure
	(In thousands)
External ratings:
Investment grade		$  11,189		$  416		$   -		$  11,605
Split ratings		15		-		-		15
Non-investment grade		22		-		-		22
Internal ratings:
Investment grade		57		-		-		57
Non-investment grade		338		-		-		338
Total		$  11,621		$  416		$   -		$  12,037

The Company provides for losses due to market and credit risk. Net credit risk for the Company’s largest counterparty as of March 31, 2011 was $1.7 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 4.1% if interest rates were to decline by 50 basis points from their levels at March 31, 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 April 28, 2011, PNMR had $259.1 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 0.92% 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 $637.6 million at March 31, 2011, of which 29.3% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at March 31, 2011, the decrease in the fair value of the fixed-rate securities would be 4.9%, or $9.2 million. The securities held by TNMP in trusts for pension and other post-employment benefits had an estimated fair value of $70.4 million at March 31, 2011, of which 25.1% 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 March 31, 2011, the decrease in the fair value of the fixed-rate securities would be 6.2%, or $1.1 million.

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

94

Equity Market Risk

The NDT and trusts established for PNM’s pension and post-employment benefits hold certain equity securities at March 31, 2011. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 58.1% of the securities held by the various PNM trusts as of March 31, 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 55.2% of the securities held by the TNMP trusts as of March 31, 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 20.1% as of March 31, 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 has also been impacted by the significant decline in the general price levels of marketable equity securities.

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 March 31, 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.

95

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 March 31, 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 March 31, 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

96

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.

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)
10.1	PNM	Amendment and Supplement No. 2 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011
10.2	PNM	Amendment and Supplement No. 3 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011
10.3	PNMR	Letter Agreement, dated as of February 28, 2011, between PNM Resources, Inc. and Cascade Investment, L.L.C.
10.4	PNMR	PNM Resources, Inc. 2011 Officer Short Term Cash Incentive Plan, dated April 29, 2011
10.5	PNMR	PNM Resources, Inc. 2011 Long-Term Incentive Transition Plan, dated April 29, 2011
10.6	PNMR	PNM Resources, Inc. Long-Term Incentive Plan Terms and Conditions, dated March 22, 2011
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
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

97

31.6	TNMP	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	PNMR	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	PNM	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.3	TNMP	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	PNMR	XBRL Instance Document
101.SCH	PNMR	XBRL Taxonomy Extension Schema Document
101.CAL	PNMR	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	PNMR	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	PNMR	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	PNMR	XBRL Taxonomy Extension Definition Linkbase Document

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: May 6, 2011	/s/ Thomas G. Sategna
	Thomas G. Sategna
	Vice President and Corporate Controller
	(Officer duly authorized to sign this report)

98

EX-10.1

Exhibit 10.1

AMENDMENT AND SUPPLEMENT NO. 2

TO

SUPPLEMENTAL AND ADDITIONAL INDENTURE OF LEASE

BETWEEN

THE NAVAJO NATION

AND

ARIZONA PUBLIC SERVICE COMPANY,

EL PASO ELECTRIC COMPANY,

PUBLIC SERVICE COMPANY OF NEW MEXICO,

SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT,

SOUTHERN CALIFORNIA EDISON COMPANY

AND

TUCSON ELECTRIC POWER COMPANY

Dated: March 7, 2011

AMENDMENT AND SUPPLEMENT NO. 2 TO

SUPPLEMENTAL AND ADDITIONAL INDENTURE OF LEASE

This Amendment and Supplement No. 2 to the Supplemental and Additional Indenture of Lease dated March 7, 2011 (this “Amendment”) is by and between the Navajo Nation (formerly known as The Navajo Tribe of Indians), acting through the Navajo Nation Council, for and on behalf of the Navajo Nation (hereinafter referred to as the “Nation”), as lessor, and Arizona Public Service Company (“APS”), El Paso Electric Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company (“Edison”), and Tucson Electric Power Company (formerly known as Tucson Gas & Electric Company) (hereinafter, collectively, together with their successors and assigns, referred to as the “Lessees,” and each individually referred to as a “Lessee”). The Nation and the Lessees are hereinafter collectively referred to as the “Parties.”

The Parties agree as follows:

1 BACKGROUND.

1.1 APS has leased certain premises from the Nation under that certain Indenture of Lease dated December 1, 1960 between APS and the Nation, as supplemented and amended by that certain Supplemental and Additional Indenture of Lease dated July 6, 1966, between the Nation, APS and the other Lessees, as further supplemented and amended by that certain Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease dated April 25, 1985, between the Nation, APS and the other Lessees (the “1985 Lease Supplement”; and such Indenture of Lease, as supplemented and amended, the “1960 Lease”).

1.2 Lessees have leased certain premises from the Nation under that certain Supplemental and Additional Indenture of Lease dated July 6, 1966, between the Nation and the Lessees, as supplemented and amended by the 1985 Lease Supplement (such Supplemental and Additional Indenture of Lease, as supplemented and amended, the “1966 Lease”).

1

1.3 The Parties desire to amend the 1960 Lease and the 1966 Lease to reflect certain new terms and conditions.

1.4 Edison does not intend to remain a participant in the Four Corners Project after July 2016. Accordingly, Edison intends to end its tenancy under the Lease upon the earlier of the sale of its interest in the Four Corners Project or July 6, 2016. The date on which Edison ends its tenancy, as set forth in the preceding sentence, is referred to as the “Amendment 2 Termination Date.”

1.5 Upon the Amendment 2 Termination Date, this Amendment shall terminate.

1.6 The 1960 Lease and the 1966 Lease are amended only as set forth in this Amendment. To the extent, however, that there is any conflict between the 1960 Lease and this Amendment or the 1966 Lease and this Amendment, this Amendment shall govern.

1.7 This Amendment is not intended to and does not merge the leasehold estates of the 1960 Lease and the 1966 Lease, or the rights, liabilities, or obligations (collectively, “Rights”) of the Parties set forth in the 1960 Lease and the 1966 Lease. Further, in no event shall the Lessees (except for APS) have any Rights under the 1960 Lease or with respect to the leasehold estate demised to APS under the 1960 Lease. Rather, except for APS, all the Lessees’ Rights are limited only to the Four Corners Project, as set forth in the 1966 Lease.

2 DEFINITIONS.

2.1 “§ 323 Grant” or “§ 323 Grants” — One or more grants of rights-of-way and easements under the Act of February 5, 1948 (62 Stat. 17, 18, 25 U.S.C. § 323-328), the Act of March 3, 1879 (20 Stat. 394, 5 U.S.C. § 485), as amended, and the Acts of July 9, 1832, and July 27, 1868 (4 Stat. 564, 15 Stat. 228. 25 U.S.C. § 2) and such regulations promulgated thereunder, as are applicable, including 25 C.F.R. § 1.2 and 25 C.F.R. Part 169.

2

2.2 “§ 323 Grant Land” — Has the meaning set forth in Section 5.2.

2.3 “Annual Payment” — Except for (i) payments owed to the Nation under the existing Settlement and Closing Agreements that the Nation has executed with each individual Lessee, (ii) payments that will be owed to the Nation under the Settlement and Closing Agreements set forth in Section 14, and (iii) the payment set forth in Section 4.5, the total and sole payment that shall be made by (X) APS to the Nation, in consideration for the rights set forth in the 1960 Lease, including, but not limited to, (a) all leasehold rights, (b) the Existing § 323 Grants, and (c) the Renewed § 323 Grants; and by (Y) the Lessees to the Nation, in consideration for the rights set forth in the 1966 Lease, including, but not limited to, (a) all leasehold rights, (b) the Existing § 323 Grants, and (c) the Renewed § 323 Grants.

2.4 “Communication Sites” — The communication sites and related facilities identified within item 5 of Exhibit B.

2.5 “Existing § 323 Grants” — The § 323 Grants set forth on Exhibit B.

2.6 “Four Corners Project” — Has the meaning set forth in the 1966 Lease.

2.7 “Initial Four Corners Plant” — Has the meaning set forth in the 1966 Lease.

2.8 “Plan” — Has the meaning set forth in Section 7.1.

2.9 “Plant” — For convenience only, and not to merge the leasehold estates under the 1960 Lease and the 1966 Lease, a reference to the Initial Four Corners Plant and the Four Corners Project, respectively.

2.10 “Renewed § 323 Grants” — Has the meaning set forth in Section 4.2.

3

2.11 “Navajo Nation Lands” — Has the meaning set forth in the 1966 Lease for the term “Reservation Lands.”

2.12 “Secretary” — The Secretary of the United States Department of the Interior or his or her duly authorized designee, representative, or successor.

2.13 “Transmission Lines” — The electrical transmission lines and related facilities identified within items 3 and 4 of Exhibit B.

3 TERM.

3.1 This Amendment shall become effective when it has been signed by the Lessees and subsequently signed by the Nation’s duly authorized representative, pursuant to a Navajo Nation Council Resolution approving this Amendment.

3.2 The Navajo Nation Council Resolution approving this Amendment, and signature by the Nation’s duly authorized representative, shall be deemed to be sufficient legal approval by the Nation of this Amendment.

3.3 This Amendment shall terminate on the Amendment 2 Termination Date.

3.4 In the event this Amendment terminates as a result of the arrival of July 6, 2016, Edison shall not be relieved of any of its continuing or accrued and unfulfilled or unperformed obligations to the Nation under the 1966 Lease, and Edison shall retain all of its rights under the 1966 Lease with respect to such continuing obligations.

4 NATION’S CONSENT TO § 323 GRANTS BY SECRETARY FOR THE PLANT, TRANSMISSION LINES, AND COMMUNICATION SITES.

4.1 The Nation has previously consented to, and the Secretary has granted, the Existing § 323 Grants, and the renewal, extension or reissuance of each Existing § 323 Grant will be necessary.

4

4.2 The Nation consents and covenants to consent now, and for the terms of each of the 1960 Lease and the 1966 Lease (collectively, “Consents”), that the Lessees shall have the right to obtain, by grant from the Secretary, and the Nation Consents to the grant by the Secretary, of renewed, extended, or reissued § 323 Grants for the rights-of-way covered in the Existing § 323 Grants. (Such renewed, extended, or reissued § 323 Grants are referred to as the “Renewed § 323 Grants”).

4.3 The Nation and Lessees will cooperate fully with each other and the Secretary to obtain the Renewed § 323 Grants.

4.4 The Navajo Nation Council Resolution approving this Amendment shall be deemed to be sufficient legal approval by the Nation for the Renewed § 323 Grants. No further consideration shall be required by the Nation in order for the Secretary to issue the Renewed § 323 Grants.

4.5 The Lessees shall provide the Nation a copy of applications for the Renewed § 323 Grants, and each application shall be accompanied by a payment of no more than $800 per application.

4.6 The Existing § 323 Grants and the Renewed § 323 Grants shall be additional and supplementary to, separate and independent from, and not conditioned upon the leasehold rights leased to APS under the 1960 Lease and to the Lessees under the 1966 Lease; and a termination of either the 1960 Lease or the 1966 Lease for any reason shall not terminate any §323 Grant, and a termination of any § 323 Grant for any reason, shall not terminate the 1960 Lease or the 1966 Lease.

5

4.7 The Nation agrees to support the renewal, extension, or reissuance of the Existing § 323 Grants as categorically excluded under section 3.2A of the Bureau of Indian Affairs’ 2005 National Environmental Policy Act Handbook. If the Secretary determines that additional environmental impact analysis is required, the Nation hereby grants Lessees access to all Navajo Nation Lands necessary to complete such additional analysis. Lessees will work with the appropriate Navajo Nation agencies to effectuate any necessary access to any Navajo Nation Lands. The Nation also agrees to assist the Lessees in completing such analysis and to take reasonable actions to reduce the time and cost required to complete such analysis.

4.8 Except as set forth in the 1960 Lease, APS shall not change the voltages of the Transmission Lines without the Nation’s prior approval.

4.9 Under no circumstances shall any § 323 Grant be interpreted as granting a fee simple interest to the Lessees or any other property interest, except as set forth in the § 323 Grant.

5 ADDITIONAL TERMS REGARDING § 323 GRANTS FOR TRANSMISSION LINES.

5.1 The provisions of Section 5.2 through Section 5.7, Section 11, and Section 13 below constitute a separate agreement between the Nation and APS. In no event shall any default, action or omission by APS under Section 5.2 through Section 5.7, Section 11, or Section 13 below have any effect on any other Parties’ rights, privileges, duties, obligations and liabilities under the remainder of this Amendment.

5.2 The Navajo Nation Lands subject to an Existing § 323 Grant or a Renewed § 323 Grant and pertaining only to the Transmission Lines shall hereinafter be referred to as “§ 323 Grant Land.”

5.3 The use of the § 323 Grant Land shall be strictly limited to constructing, reconstructing, replacing, repairing, operating and maintaining the Transmission Lines. Any other use of the § 323 Grant Land shall require the consent of the Nation. The consent of the Nation may be given, given upon conditions, or denied at the sole discretion of the Nation.

6

5.4 The Nation shall be under no obligation to forego the use of the § 323 Grant Land or any portion or lands burdened by the § 323 Grant Land, or to refrain from authorizing any use of said lands by any third party, including but not limited to, the exploration for and development and transportation of coal, oil, gas, or other natural resources located within or beneath said lands, except to the extent that such use physically interferes with the operation and maintenance of the Transmission Lines or interferes with the purposes of the § 323 Grants.

5.5 Upon the Nation’s proposed authorization of the use of the § 323 Grant Lands by any third party, which new use may occupy the § 323 Grant Lands or otherwise burden the § 323 Grant Lands, the Nation agrees to notify APS and commence good faith consultation with APS prior to the Nation’s final approval of said third party use. Prior to the Nation’s final approval, the Nation shall require the third party to enter into an agreement with APS, which agreement must be acceptable to APS, to indemnify, defend, and hold APS harmless from any and all liability arising from the third party’s use, interest, and activities within the § 323 Grant Land.

5.6 Five years prior to the expiration of a Renewed § 323 Grant, or as soon as practicable after any earlier termination of a Renewed § 323 Grant, APS and the Nation shall meet to discuss whether APS will leave in place all, some, or none of the Transmission Lines. If APS and the Nation cannot agree to terms regarding the disposition of one or more of the Transmission Lines, APS shall remove the Transmission Line(s) for which no agreement is reached, in accordance with the

7

Lease and applicable laws and requirements, and shall leave the § 323 Grant Land in good condition. On the expiration date of a Renewed § 323 Grant, APS shall have ninety (90) days to peaceably and without legal process deliver the possession of the § 323 Grant Land, with or without the Transmission Lines, as the case may be. In the event a Renewed § 323 Grant is terminated early, APS shall have six months to peaceably and without legal process deliver the possession of the § 323 Grant Land for such terminated § 323 Grant, with or without the Transmission Lines, as the case may be. If delivery cannot be performed on or before such 90-day period or six month period, as the case may be, APS and the Nation shall commence good faith negotiations for compensation, fees or damages to be paid to the Nation for prospective periods of occupation, use, or burden of the § 323 Grant Lands.

5.7 Holding over by APS after the expiration or early termination of a Renewed § 323 Grant shall not constitute an extension/renewal thereof, or give APS any rights in or to the § 323 Grant Lands. Holding over after expiration or early termination of a Renewed § 323 Grant shall not give APS any rights via a Renewed § 323 Grant. Following expiration or early termination of a § 323 Grant, the act of applying for a § 323 Grant from the Secretary shall not give APS any rights to the § 323 Grant land.

6 NATION’S SUPPORT OF ENVIRONMENTAL REVIEWS AND § 323 GRANTS.

The Nation shall work with the Lessees to obtain the necessary regulatory approvals and to advocate on behalf of the Lessees in support of any National Environmental Policy Act, Endangered Species Act, or National Historic Preservation Act analyses; § 323 renewals or extensions; or any other requirements of the Department of the Interior (“DOI”) or the Nation that are prerequisites necessary to conduct the operations of the Plant, Transmission Lines, and Communication Sites. In its interactions with the DOI, the Nation shall support the interests of the Lessees and advocate positions that support the continued operations of the Plant, Transmission Lines, and Communication Sites.

8

7 EMPLOYMENT AT THE FOUR CORNERS GENERATING STATION.

Section 19 of the 1960 Lease, Section 24 of the 1966 Lease and Section 25 of the 1966 Lease (as amended by Section 12 of the 1985 Lease Supplement) are deleted in their entirety and replaced as follows:

7.1 Without limiting the scope or effectiveness of the provisions of Section 17 of the 1960 Lease (Operation of Power Plant) or Section 22 of the 1966 Lease (Operation of Enlarged Four Corners Generating Station), APS and the Lessees shall comply with the terms of the Four Corners Generating Station Preference Plan (the “Plan”), attached as Exhibit C.

7.2 In the event that, in the opinion of their counsel, federal law develops in the future to permit APS and the Lessees, respectively, to grant a preference in employment based on tribal affiliation, as distinguished from a “Native American Indian” preference in employment, APS and the Lessees shall practice a Navajo preference in employment at the Plant in accordance with the requirements of this Section 7 and the Plan.

7.3 If, at any time, APS’s then current Collective Bargaining Agreement (which governs labor at the Plant), as negotiated by APS in its sole discretion, conflicts with this Section 7 or the Plan, then APS’s Collective Bargaining Agreement shall take precedence.

9

8 ADVISORY COMMITTEE.

APS, the Lessees, and the Nation shall establish a Four Corners Advisory Committee for the purpose of promoting open dialogue between them regarding operations of the Plant.

8.1 The Committee shall consist of two members of the Navajo Nation Government with experience in energy-related matters, one from the executive and one from the legislative branch, and two senior officials representing APS and the Lessees, who shall be tasked to work together and in consultation with their respective leaderships to resolve concerns raised by APS and the Lessees or the Nation in a mutually beneficial manner. The Committee shall meet regularly, but no less than two times a year. Discussion topics and updates may include voluntary compliance agreements, the impact of plant operations on the Nation’s members and surrounding communities and emerging issues.

8.2 APS and the Lessees or the Nation may submit disagreements and disputes to the Committee for discussion and possible resolution. Decisions of the Committee shall be in the nature of recommendations and shall not be binding on APS and the Lessees or the Nation.

9 ANNUAL PAYMENT.

9.1 The Annual Payment shall replace all compensation for rents, rights of way, or otherwise, set forth in the § 323 Grants (as to the § 323 Grant Land), the 1960 Lease and the 1966 Lease, as applicable. All sections of the aforementioned documents imposing a payment obligation on APS and the Lessees are hereby deleted.

10

9.2 The Annual Payment, which shall be $7,000,000 (in 2011 dollars), shall begin on July 6, 2011. All subsequent Annual Payments shall be subject to annual adjustments, based upon changes in the April Consumer Price Index U.S. City Average for All Urban Consumers, published by the U.S. Bureau of Labor Statistics (“CPI”). The annual CPI adjustment for the Annual Payment shall be as set forth in Exhibit D.

9.3 On or before July 6 of each year, APS and the Lessees shall submit one check for the Annual Payment to the Nation and indicate the adjustment required by the CPI.

9.4 No Lessee shall be responsible or liable to the Nation for the payment of any portion of such Annual Payment of any other Lessee. In the event that one or more Lessees fails to pay the Nation its portion of such Annual Payment at the time such Annual Payment is submitted to the Nation, APS (or the then operator of the Plant) shall inform the Nation of the name of the Lessee(s) failing to make the Annual Payment and the specific amount of each such Lessee’s shortfall. In the event the Nation incurs costs associated with obtaining the required Annual Payment owed, the Nation shall be entitled to recover from the defaulting Lessee(s) its associated costs, including, but not limited to, attorney’s fees, filing fees and interest accrued. A list of each Lessee’s portion of the Annual Payment shall be provided to the Nation.

9.5 The Nation agrees that the Annual Payment payable by APS and the Lessees constitutes fair and adequate consideration for the rights granted in the 1960 Lease, the 1966 Lease, the Existing § 323 Grants and the Renewed § 323 Grants.

11

9.6 Upon agreement between the Lessees, the percentage of the Annual Payment owed by each of APS and the Lessees, respectively, may be changed without the consent of the Nation. But in no event shall the amount due be less than 100% of the Annual Payment, as calculated in accordance with Section 9.2. In the event of a change in payment percentages, an updated list of each Lessee’s portion of the Annual Payment shall be provided to the Nation.

9.7 In consideration of the Annual Payment made by APS and the Lessees, respectively, the Nation releases APS and the Lessees from all and any kind of claims, suits, actions, causes of action, rights, liabilities, and obligations (the aforementioned, collectively referred to as “Claims”), whether past, present, or future, known or unknown, for or related to compensation due under the 1960 Lease or 1966 Lease, or compensation for the Existing § 323 Grants and the Renewed § 323 Grants. In consideration of the Annual Payment made by APS and the Lessees, respectively, the Nation releases APS and the Lessees from and settles all outstanding issues and potential Claims, under the 1960 Lease or 1966 Lease, or under the Existing § 323 Grants. Notwithstanding the foregoing, the release set forth in this Section 9.7 shall not apply to any claims arising under Section 11 of this Amendment.

9.8 APS and the Lessees release the Nation from and settle all outstanding issues and potential Claims under the 1960 Lease or the 1966 Lease, or under the Existing § 323 Grants. Notwithstanding the foregoing, the release set forth in this Section 9.8 shall not apply to any claims arising under Section 11 of this Amendment.

10 SURVEY OF PLANT.

10.1 APS and the Lessees and the Nation agree that part of the Annual Payment is based on their understanding that the Plant Site and the Ancillary Facilities, as identified within items 1 and 2 of Exhibit B (the “Plant Property”), comprise a total of 3,663 acres (3,600 acres, with an upper margin of error of 63 acres) (the “Expected Plant Property Acreage”).

12

10.2 APS and the Nation agree that part of APS’s share of the Annual Payment is based on their understanding that the § 323 Grant Land comprises 10,000 acres (9839.40 acres, with an upper margin of error of 172 acres) (the “Expected § 323 Grant Land Acreage”).

10.3 APS, for the § 323 Grant Land, and APS and the Lessees, for the Plant Property, shall conduct surveys of the § 323 Grant Land and the Plant Property, respectively, within twelve months for the § 323 Grant Land, and six months for the Plant Property, after the effective date of this Amendment. The Nation hereby grants APS and the Lessees access to all Navajo Nation Lands necessary to complete such surveys, and APS and the Lessees will work with the appropriate Nation agencies to effectuate any necessary access to any Navajo Nation Lands. The actual acres for the Plant Property and the § 323 Grant Land, as determined in such surveys, shall each be referred to as the “Actual Acreage.” If the Actual Acreage for the Plant Property exceeds the Expected Plant Property Acreage, or if the Actual Acreage for the § 323 Grant Land exceeds the Expected § 323 Grant Land Acreage, then Section 10.4 and, if necessary, Section 10.5 shall apply. If Section 10.4 does not apply, there shall be no adjustment to the Annual Payment and no other compensation shall be due to the Nation.

10.4 If the Actual Acreage for the Plant Property exceeds the Expected Plant Property Acreage, or if the Actual § 323 Grant Land Acreage exceeds the Expected § 323 Grant Land Acreage, APS (individually) or APS and the Lessees, as the case may be, shall have 90 days to cure and reduce the respective Actual Acreages to at or below the Expected Plant Property Acreage or Expected § 323 Grant Land Acreage, as the case may be. If the Actual Acreages are reduced accordingly, there shall be no adjustment to the Annual Payment and no other compensation shall be due to the Nation.

13

10.5 For any Actual Acreage in excess of the Expected Plant Property Acreage or Expected § 323 Grant Land Acreage that APS (individually) or APS and the Lessees fail or choose not to cure, the Annual Payment shall be adjusted in the next Annual Payment as follows: (a) for each one acre the Actual Acreage of the Plant Property exceeds the Expected Plant Property Acreage, the Annual Payment shall increase by $269, adjusted annually by the CPI (in 2011 dollars); and (b) for each one acre the Actual Acreage of the § 323 Grant Land exceeds the Expected § 323 Grant Land Acreage, the Annual Payment payable by APS shall increase by $612, adjusted annually by the CPI (in 2011 dollars).

10.6 Any adjusted Annual Payment shall be prospective only, and there shall be no true-up required for previous Annual Payments, and the Nation shall have no claims against the Lessees for additional liabilities or compensation for historic use of the Plant Property or the § 323 Grant Land related to property survey inaccuracies.

10.7 The respective surveys will not be used to acquire additional or different lands beyond what the surveys demonstrate comprise the current boundaries of the Plant Property or the § 323 Grant Lands.

11 APS’S 230kV LINES.

APS and the Nation disagree as to whether the provisions of Section 17 of the 1960 Lease (Operation of Power Plant) or Section 22 of the 1966 Lease (Operation of Enlarged Four Corners Generating Station) apply to the Existing §323 Grants listed on Exhibit B for the 230kV lines identified as (a) Flagstaff to Leupp and (b) Cholla to Leupp (collectively, the “Leupp Lines”). APS and the Nation each reserve the right to assert that the aforementioned sections apply or do not apply to the Leupp Lines, as the case may be.

14

12 DECOMMISSIONING.

Upon the decommissioning of the Initial Four Corners Plant, the Four Corners Project or any part of either facility, the final decommissioning obligations of APS as to the Initial Four Corners Plant and of the Lessees as to the Four Corners Project shall be limited to the requirements under the applicable federal environmental laws existing at the time of such decommissioning. All or any part of any such decommissioning may occur at any time during the term of either the 1960 Lease or the 1966 Lease, as applicable.

13 MOENKOPI SUBSTATION.

In the event that there is a future expansion of the Moenkopi Substation, it shall be subject to an increase in APS’s portion of the Annual Payment by $1500 per acre (in April 2009 dollars) for up to 100 acres. The $1500 per acre payment shall be adjusted annually by the CPI (in April 2009 dollars). The expansion shall be subject to all applicable regulatory requirements.

14 SETTLEMENT AND CLOSING AGREEMENTS.

Except for Edison, each Party shall execute a new Settlement and Closing Agreement in form and substance substantially similar to the proposed sample Settlement and Closing Agreement attached as Exhibit F.

15 NO CROSS DEFAULT.

Notwithstanding anything to the contrary in this Amendment, the 1960 Lease or the 1966 Lease, a default by APS under the 1960 Lease, as amended by this Amendment, shall not constitute a default by Lessees under the 1966 Lease, and a default by Lessees under the 1966 Lease, as amended by this Amendment, shall not constitute a default by APS under the 1960 Lease.

15

16 PRIMARY FUEL. The primary fuel used at the Plant shall be coal.

17 NO THIRD PARTY BENEFICIARIES.

The 1960 Lease and the 1966 Lease are not intended to confer upon any third person any rights, privileges, waivers, obligations, or remedies granted hereunder.

18 EXECUTION IN COUNTERPARTS.

This Amendment may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument and as if all of the Parties to the aggregate counterparts had signed the same instrument. Any signature page of this Amendment may be detached from any counterpart thereof without impairing the legal effect of any signatures thereon, and may be attached to other counterparts of this Amendment identical in form hereto but having attached to it one or more additional signature pages.

16

This Amendment has been executed by the duly authorized representatives of the Parties, effective as set forth in Section 3.1.

THE NAVAJO NATION
By:	/s/ Ben Shelly
	Printed Name: Ben Shelly
	Its: President

State of Arizona

County of Apache

The foregoing instrument was acknowledge before me this 7th day of March, 2011 by Ben Shelly the PRESIDENT of

(Name)              (Title)                             

THE NAVAJO NATION, on behalf of The Navajo Nation.

/s/ Angela Cody

Notary Public

My Commission Expires:

    

ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, in its individual capacity and as a Lessee
By:	/s/ Mark A. Schiavoni
	Printed Name: Mark A. Schiavoni
	Its: Senior Vice President, Fossil

State of Arizona

County of Maricopa

The foregoing instrument was acknowledge before me this 8th day of November, 2010 by Mark A. Schiavoni the Senior Vice

(Name)                     (Title)          

President, Fossil of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of the corporation.

	/s/ Norann Asciutto
	Notary Public
My Commission Expires: 2-27-14

17

Reviewed and Approved Legal Department	EL PASO ELECTRIC COMPANY, a Texas corporation
/s/ [ILLEGIBLE]	By:	/s/ David W. Stevens
		Printed Name: David W. Stevens
		Its: CEO

State of Texas

County of EL Paso

The foregoing instrument was acknowledge before me this 8^th day of November, 2010 by David W. Stevens the CEO of EL

(Name)               (Title)                  

PASO ELECTRIC COMPANY, a Texas corporation, on behalf of the corporation.

		/s/ Carolina Pena
		Notary Public
My Commission Expires: 3-24-2011
	PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation
	By:	/s/ Patricia K. Collawn
		Printed Name: Patricia K. Collawn
		Its: President & CEO

State of New Mexico

County of Bernalillo

The foregoing instrument was acknowledge before me this 8^th day of November, 2010 by Patricia K. Collawn the President &

(Name)                      (Title)           

CEO of PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation, on behalf of the corporation.

	/s/ [ILLEGIBLE]
	Notary Public
My Commission Expires:

18

September 12, 2012	SOUTHERN CALIFORNIA EDISON COMPANY, a California Corporation
	By:	/s/ RW Krieger
		Printed Name: RW Krieger
		Its: Vice President

State of California

County of Los Angeles

The foregoing instrument was acknowledge before me this 8^th day of November, 2010 by Jean E. Lambrecht the Notary of

(Name)                 (Title)                

SOUTHERN CALIFORNIA EDISON COMPANY, a California corporation, on behalf of the corporation.

/s/ Jean E. Lambrecht

Notary Public

My Commission Expires:

June 8, 2013

TUCSON ELECTRIC POWER COMPANY, an Arizona Corporation
By:	/s/ Michael J. DeConcini
	Printed Name: Michael J. DeConcini
	Its:	Senior Vice President and Chief Operating Officer

State of Arizona

County of Pima

The foregoing instrument was acknowledge before me this 8th day of November, 2010 by Michael J. DeConcini the Sr. Vice

(Name)                                         

President & Chief Operating Officer of TUCSON ELECTRIC POWER COMPANY, an Arizona corporation, on behalf of the 

                      (Title)

corporation.

	/s/ Janice Spencer
	Notary Public
My Commission Expires: 8/8/11

19

SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT, an agricultural improvement district organized under the laws of the State of Arizona.

By:	/s/ David Rousseau	Reviewed by SRP Legal Services
	David Rousseau, President or
	John R. Hoopes, Vice President	By:	/s/ Kanlee Ramaley
			Signature
Date:	11/23/2010
			Kanlee Ramaley
			Printed Name
		Date:	11/23/2010

Attest and Countersign:

By:	/s/ Terrill A. Lonon
	Terrill A. Lonon, Secretary or
	Stephanie K. Reed, Assistant Secretary
Date: 11/23/2010

State of Arizona

County of Maricopa

The foregoing instrument was acknowledge before me this 23rd day of November, 2010 by David Rousseau the President

(Name)                  (Title)               

of SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT, an agricultural improvement district organized under the laws of the State of Arizona.

	/s/ Stephanie K. Reed
	Notary Public
My Commission Expires: August 5, 2011

20

EXHIBIT A

This exhibit intentionally not used.

Exhibit B

Item	Existing § 323 Grants	Property or Facility	APS File #	Grant Date	Expiration Date	Acres
1	Plant Site	Amended Original Lease (Units 1-3)		12/01/60	07/06/16
		New Lease (Units 4-5)		07/06/66	07/06/16
							3,466.42
2	Ancillary Facilities	Utah Mine Haul Road (Communication Lines and Access Road)	IN-13	07/2861	07/28/11		19.25
		Plant — Coal Lease Area — 69 kV	IN-15	12/15/61	12/15/11		3.75
		Pumping Station to Plant Access Road & Pipeline	IN-12	04/02/62	04/02/12		40.91
		River Pumping Station to Plant — 69 kV	IN-11	04/02/62	04/02/12		21.74
		Plant — EPNG Bridge / Access Rd	IN-16	07/03/63	07/03/13		37.57
		Pumping Station to Plant Access Road & Pipeline Addition	IN-92	04/21/69	04/21/19		10.36
							133.58
3	500 kV ROW	El Dorado 500 kV (Navajo portion only)	IN78 INH-79, INH-80	03/22/67	03/22/17		3,959.29
	345 kV ROW	Four Corners to Cholla	IN-17	05/26/61	05/26/11		5,658.91
	230 kV ROW	Flagstaff to Leupp	IN-4	09/12/57	09/12/07		102.82
		Cholla to Leupp	IN-7	09/21/60	09/21/10		249.16
4	Substation Sites	12 kV line and Roadway to Moenkopi Switchyard	INH-88	04/24/70	04/27/95		1.12
		Leupp Substation	IN-5	05/06/59	05/06/09		.43
		Moenkopi Switchyard	INH-83	04/09/68	04/09/18		211.09
5	Communication Sites	Preston Mesa Communication Site	IN-1182	12/30/96	12/30/14		0.23
		Jacks Peak Communication Site	IN-1181	04/16/02	04/15/17		1.75
		Dezza Bluff Communication Site	IN-1357	12/15/97	12/14/17		0.08
		Zilnez Mesa Microwave Site, Navajo Reservation	IN-113	01/03/73	01/03/23		2.40
		Roof Butte Communication Site	IN-85	07/07/70	07/07/20		0.02
		Marsh Pass Communication Site	IN-116	01/03/73	01/03/23		3.90

* Certain of the terms used to describe the listed property or facilities have the meanings given to them in the 1960 Lease and 1966 Lease.

Exhibit C

FOUR CORNERS GENERATING STATION

PREFERENCE PLAN

March 7, 2011

Table of Contents

I. INTRODUCTION	1
II. PREFERENCE POLICY STATEMENT	1
III. SELECTION	1
IV. GOALS	2
V. TRAINING	3
VI. RECRUITMENT/ADVERTISING FOR REGULAR EMPLOYEES	3
VII. ADVERTISING/RECRUITING FOR TEMPORARY EMPLOYEES	4
VIII. CONTRACT LABOR/SERVICES	4
IX. CROSS CULTURAL COMMUNICATIONS PROGRAM	4
X. DISPUTE RESOLUTION FOR EMPLOYEES	4
XI. ENTIRE AGREEMENT; NO THIRD PARTY BENEFICIARIES	5

I. INTRODUCTION

The purpose of this Preference Plan is to clarify and delineate Arizona Public Service Company’s (“APS”) Indian Preference Plan for the Four Corners Generating Station (“Four Corners”) and specifically, the procedures for giving preference in employment to Indians.

II. PREFERENCE POLICY STATEMENT

Employment at Four Corners is based on qualifications without regard to race, color, creed, religion, national origin, sex, or age, except that preference will be given to qualified Indians, provided, however, that to the extent allowed by law (as set forth in Section 7.2 of the Amendment, to which this Preference Plan is attached), APS will give preference to qualified Navajos rather than to Indians. Each member of APS’s management is responsible for implementing this policy in his/her areas and is held accountable for it in the same way each manager is held accountable for other company policies. In particular, the Plant Manager for Four Corners has overall accountability and responsibility for implementation of this Preference Plan.

III. SELECTION

In order to conduct operations at Four Corners in a safe and effective manner, all positions must be filled by persons qualified to perform the work required. APS has procedures to evaluate the qualifications (knowledge, skills and abilities) required for each job position. In general, these job qualifications are documented in “job descriptions” maintained by APS’s Human Resource Department. Employees may also obtain a copy of their job descriptions by contacting their supervisors.

Job requirements consist of standards which identify the skills, education, and experience necessary to perform a particular job. These job requirements are the basis for hiring decisions and are also used to formulate employee training programs for job classifications with few incumbent-Indian employees. Hence, it is important that the job descriptions describe the true requirements of the job. For this reason, APS will review its job descriptions to assure that the job qualifications are relevant to the job requirements.

Qualifications are assessed on the basis of performance reviews, skills evaluations, experience and education, as appropriate for the position under consideration. Supervisors (and previous employers, in the case of external applicants) may be contacted. Skills may be evaluated by written tests, skill demonstrations, or by supervisory interview. Tests will be validated for job relevancy.

APS is committed to Indian preference in employment. Preference will be given to Indians who possess the skills and abilities to fulfill the job requirements established above.

1

IV. GOALS

The purpose of this Preference Plan is to provide a means to increase the employment of Indians at Four Corners, in both regular full-time and temporary positions. In particular, APS intends to focus on increasing the overall employment of Indians at Four Corners and promoting Indians into management positions.

Analysis of Indian employment levels by job classification will lead to establishing goals for job placement and training. These goals will be reviewed annually to evaluate the progress made toward the objective, and revised as necessary.

The commitment of APS is to offer available job opportunities to Indians who satisfy job requirements, whether the person is a current employee or a non-employee identified through recruitment and advertising. Through the adoption and implementation of training programs at Four Corners, the long-range goal is to develop a pool of Indian candidates qualified for all positions.

Openings created through resignation, discharge, transfer, promotion, or a newly created position cause the posting of an internal “bid” and create opportunities for internal movement through the bid process. Bidding is the established process by which job vacancies are announced, advertised and filled. When vacancies occur, employees, who feel they have the qualifications for a particular job, may submit their internal applications (bids) for consideration.

The bid process frequently creates a cascading effect, as employees vacate existing jobs to fill positions that result from another employee accepting a bid to fill the original vacancy. When an Indian bidder accepts a position vacated by another Indian, the net effect on the overall percentage of Indian employment is zero. While Indian bidders will be given preference in accordance with this Preference Plan, an increase in the total percentage of Indian employees at Four Corners can be expected only when the cascading effect of the bid system results in the employment of external Indian candidates.

Nevertheless, the potential for increasing the number of Indian employees is greater in certain job classifications than in others. Some of these job classifications are:

• First and second level supervision

• Operations (Operator Trainee through Control Operator)

• Machinist

• Plant Mechanic

• Electrician

• Equipment Operator

• Plant Chemist

• Scheduler

2

Four Corners management will give these job classifications particular attention to increase employment of Indians. Additionally, technical and professional recruiting will be increased to locate, identify, and employ suitable Indian candidates for engineers, technicians, and professional positions.

V. TRAINING

When there are too few qualified Indian bidders, internal training programs to increase the availability of Indian bidders may be appropriate. Training programs should focus on raising the level of skills, knowledge and abilities of Indians in “feeder jobs.” These are jobs which typically provide employees for higher level jobs, particularly when the lower level job has skill, knowledge and ability requirements that are prerequisites for a higher level job. Training should continue until the goal has been met. Other “in-place” training programs, such as apprenticeships and operations training, are on-going and continue to provide trained replacements for journeymen.

Indians will be encouraged to enhance their careers at APS by taking advantage of on-the-job training, apprenticeships, and in-house and off-the-job educational courses. As a specific part of this Preference Plan, the following actions will be taken to provide opportunities for Indians to advance to journeyman-level and supervisory positions.

1. New apprenticeships will be awarded only to qualified Indians.

2. Currently employed Indian journeymen will be selected for supervisory training to make them better qualified for future opportunities in foreman positions.

Because of the magnitude of the work and its accompanying time constraints, virtually everyone at Four Corners is affected by an overhaul. Four Corners has chosen to supplement the knowledge, skills and experience of its regular full-time employees with those of temporary workers with job specific skills. During an overhaul, where possible, regular full time employees are upgraded to higher level skill positions including supervisory positions. In this manner, employees may further expand the practical application of their technical and supervisory skills.

VI. RECRUITMENT/ADVERTISING FOR REGULAR EMPLOYEES

Recruitment is any activity that causes individuals to apply for employment. Advertising is one method of recruitment. Examples of other methods include meetings with graduating college seniors, participation in trade fairs, and day programs.

Since most regular full-time jobs at Four Corners are filled internally, a large recruitment effort is not needed. Thus, recruitment of regular full-time employees should be limited to those positions which are not filled by Indians internally. For purposes of this Preference Plan, recruitment will concentrate on jobs in which Indians are underutilized.

3

In an effort to attract qualified Indian applicants, contacts with key organizations throughout the Navajo Reservation will be maintained, although contacts within the Western Navajo Agency will be emphasized. In addition, Four Corners will work with appropriate tribal agencies to develop other potential recruitment sources.

Universities, vocational schools, Joint Training and Partnership Act classroom training programs, the Navajo Division of Education, the ONLR, and employment service offices located in the vicinity of Four Corners will be included in the recruitment and advertising efforts of Four Corners. Technical and professional jobs will be emphasized in recruitment efforts at colleges, universities, and in periodic advertisements to attempt to locate and identify suitable Indian candidates for employment opportunities.

Advertising and recruiting efforts will include a statement that APS at Four Corners recognizes Indian preference in employment. The following statement will be included in all advertisements for employment opportunities at Four Corners and on bid sheets posting jobs at Four Corners:

APS follows a policy of giving preferential treatment to Indians in connection with employment at the Four Corners Generating Station.

VII. ADVERTISING/RECRUITING FOR TEMPORARY EMPLOYEES

Each year, temporary employees are hired for certain specific assignments at Four Corners. Only when no qualified Indian applicant is found, after a thorough review of returning Indian applicants, existing files on temporary Indian employees, and new applications from Indians (generated by advertising), will a temporary position be filled by a non-Indian.

VIII. CONTRACT LABOR/SERVICES

APS will select qualified Indian-owned businesses, when available, to provide contract labor or services at Four Corners. APS will notify its vendors (a) of the employment and contracting preference policy at Four Corners; and (b) that they are expected to comply with applicable laws and regulations.

IX. CROSS CULTURAL COMMUNICATIONS PROGRAM

APS will develop and implement a cross-cultural program designed to provide a forum for Indian and non-Indian employees to openly examine and discuss the culturally significant customs, beliefs, values, and social mores that all individuals bring with them to the workplace.

X. DISPUTE RESOLUTION FOR EMPLOYEES

APS acknowledges the value of maintaining a work environment free of prejudice and discrimination. Nevertheless, despite even the best of intentions, complaints do arise, and the parties have determined that complaints of whatever nature are best handled internally, without the involvement of external agencies. Therefore, employees are encouraged to take advantage of APS’s existing internal processes. Through this approach, a wide variety of employment related complaints may be addressed and resolved.

4

If Navajo Nation officials become aware of an employment concern at Four Corners, the Navajo Nation must bring the issue to the Advisory Committee, formed pursuant to the Lease (to which this Preference Plan is attached), for resolution.

XI. ENTIRE AGREEMENT; NO THIRD PARTY BENEFICIARIES

This Preference Plan is the entire agreement between the Parties concerning its subject matter and supersedes all prior agreements and understandings, whether or not written, including without limitation the letter agreement dated March 8, 1985 between APS and the Navajo Nation and signed by G. Mark De Michele and Peterson Zah. This Preference Plan also is not intended to confer upon any person other than the Parties any rights, privileges, waivers, obligations or remedies granted hereunder.

5

Exhibit D

Annual Payment for 2012

$7,000,000.00x	CPI for April 2012
	April 2011 CPI

Annual Payment for all subsequent years

7,000,000.00x	CPI for April in year which Annual Payment is due
	April 2011 CPI

Exhibit E

This exhibit intentionally not used.

Exhibit F

(Includes Exhibits A-D of the Restated and Amended Settlement and Closing Agreement)

DRAFT

11/4/2010 3:30 PM

Restated and Amended Settlement and Closing Agreement

This Restated and Amended Settlement and Closing Agreement (the “Restated Agreement”) amends the Settlement and Closing Agreement dated August 15, 2002 (“Original Agreement”) and is entered into as of the Effective Date (as defined in Section 18) by Arizona Public Service Company (“APS”) and the Office of the Navajo Tax Commission (“ONTC”), acting on its own behalf and, pursuant to Section 103 of the Navajo Nation Uniform Tax Administration Statute (“UTAS”), on behalf of the Navajo Nation. APS and the ONTC may be referred to herein individually as a “Party” or collectively as the “Parties.”

Recitals

A. Pursuant to Section 105 of UTAS, the ONTC, on behalf of the Navajo Nation, issued an assessment to APS on [Date] seeking to assess the Possessory Interest Tax (“PIT”) on APS in connection with its ownership and operation of the Four Corners Power Plant (the “Plant”), switchyards, and transmission and distribution facilities within the Navajo Nation (hereinafter, the Plant, switchyards, and transmission and distribution facilities within the Navajo Nation are collectively referred to as the “Facilities”). Pursuant to Regulation 1.125 of the ONTC Tax Administration Regulations, the ONTC also issued on [Date] a private ruling asserting that it has jurisdictional authority to impose the Business Activity Tax (“BAT”) upon APS’ activities related to the Facilities. Pursuant to Section 133 of UTAS, the ONTC is entering into this Restated Agreement.

B. APS and the other participants in the Plant (collectively, the “Participants”) assert that neither the Navajo Nation nor the ONTC has jurisdictional authority to impose any tax on APS, the Participants or the Facilities based on (i) certain agreements between the Navajo Nation, APS and Participants, including without limitation, certain covenants in leases entered into by APS, the Participants and the Navajo Nation and approved by the United States (“Leases”) and in federal grants of rights-of-way issued to APS and the Participants by the United States (“Grants”), (ii) the location of the Facilities on federally granted rights-of-way, (iii) the non-Indian character of APS and the Participants, and (iv) relevant case law.

1

C. The ONTC asserts that it possesses jurisdictional authority to administer taxes enacted by the Navajo Nation with respect to the Participants, including APS, and the Facilities based on (i) certain agreements between the Navajo Nation, APS and the Participants, including without limitation, certain covenants in the Leases and Grants, (ii) the location of the Facilities on lands held in trust by the United States for the benefit of the Navajo Tribe, and (iii) relevant case law.

D. The Parties entered into the Original Agreement for purposes of settling the dispute and to avoid litigation over the question of the jurisdictional authority of the Navajo Nation and ONTC to tax the Facilities and APS, based on its ownership interest in and operation of the Facilities.

E. The Parties desire to restate, amend and extend the Original Agreement and are thus entering into this Restated Agreement in accordance with the express terms set forth below.

WHEREFORE, THE PARTIES AGREE AS FOLLOWS:

1. Settlement Payments. Subject to the terms and conditions contained in this Restated Agreement, APS will make settlement payments as specified below (“Settlement Payments”):

a. PIT Settlement Payments.

(i) Beginning with calendar year 2001 and continuing through July 7, 2041 (the “Amended Term”), APS will pay to ONTC the following amount as a PIT Settlement Payment for the APS-owned Facilities, subject to adjustment as provided in subsection a(ii) of this Section 1:

Calendar Year	PIT Settlement Payment
2001	$2,993,515.00
2002 – 2003	$5,987,030.00 per year
2004 – 2040	$6,342,600 per year
2041	$3,171,300.00

2

(ii) Beginning July 8, 2016 and continuing through July 7, 2041, the PIT Settlement Payment is subject to reduction in the event APS and/or the Participants permanently shut down any of the Facilities and/or unit(s) of the Plant in which APS has an ownership interest, including but not limited to the permanent shut down of the entire Plant (the “Permanently Shut Down Facilities”). For any Permanently Shut Down Facilities salvage value will be determinative of value, and salvage value will be based on 5% of original or acquisition cost of the Permanently Shut Down Facilities in question. In the event of any permanent shut down under this Section 1a(ii), the PIT Settlement Payment will be recalculated in two steps:

a. Step One: PIT Settlement Payment will be proportionally reduced by multiplying the PIT Settlement Payment by a factor that represents the ratio of the original or acquisition cost of the APS-owned Facilities within the Navajo Nation that are not Permanently Shut Down Facilities divided by the total original or acquisition cost of the APS-owned Facilities.

b. Step Two: The proportionately reduced PIT Settlement Payment derived under Step One will then be increased by adding the product of a 3% in-lieu-of tax rate and the salvage value (i.e., 5% of original or acquisition cost) of the Permanently Shut Down Facilities. A sample calculation in included as Exhibit D to this Restated Agreement.

(iii) In the event APS constructs a new unit or units at the Plant during the Amended Term, the PIT Settlement Payment will be proportionally increased by an amount that represents the product obtained by multiplying the original or acquisition cost of the new APS-owned unit or units by the following factor:

a. The PIT Settlement Payment of $6,342,600 divided by the original or acquisition cost of the APS- owned Facilities within the Navajo Nation as of the Effective Date of this Restated Agreement. A sample calculation in included as Exhibit 1 to this Restated Agreement

(iv) APS will pay the PIT Settlement Payment specified above (as may be adjusted pursuant to Section 1a(ii) or Section 1a(iii), above) for calendar years 2002-2040 on a semi-annual basis, with the first half for each calendar year due November 1 and the second half due May 1 of the following year. APS will pay the PIT Settlement Payment specified above for calendar year 2041 on or before November 1, 2041. On or before June 1 of each calendar year during the term of this Restated Agreement, APS will provide to the ONTC, for informational purposes only, the form attached as Exhibit A.

3

(v) Interest on any late payment of the PIT Settlement Payment will be computed from the date the PIT Settlement Payment was first due to the date such payment is received by the ONTC. The rate of interest on any late payment will be equal to the rate then being used by the Internal Revenue Service for an underpayment of taxes by an individual. If APS fails to timely pay the PIT Settlement Payment, APS also will pay an additional amount equal to 5% of its PIT Settlement Payment. For each full month the payment is overdue, APS will pay an additional amount equal to 0.5% of its PIT Settlement Payment; provided, however, that the maximum additional amount APS must pay for the failure to timely pay shall not exceed 10% of the PIT Settlement Payment amount due. If APS fails to timely provide the Report for PIT Settlement Payment, attached as Exhibit A, as required by Section 1(a)(iv) of this Restated Agreement, APS will pay an additional 5% of its PIT Settlement Payment due for the period for each month or fraction thereof that the Report for PIT Settlement Payment is not provided; provided, however, that the minimum additional amount to be paid for failure to timely provide such Report for PIT Settlement Payment shall be $50 and the maximum additional amount shall not exceed 25% of APS’ PIT Settlement Payment for that period. For good cause shown, the ONTC may in its discretion relieve APS from all or part of the requirements imposed under this Section 1.a(v).

(vi) APS will provide, within six (6) months of the Effective Date of this Restated Agreement, a schedule of original or acquisition cost for the Facilities in which APS has an ownership interest (including the Permanently Shut Down Facilities) for use in connection with the calculations provided for in Section 1.a(ii). In addition, if APS constructs a new unit or units at the Plant for purposes of Section 1.a(iii), APS will provide a schedule of original or acquisition cost for such new unit or units within six (6) months after its/their completion, for use in connection with the calculations provided for in Section 1.a(iii).

(vii) The ONTC expressly agrees that APS is hereby released from any obligation and will not be required or requested to make any other payment with respect to any other amounts that the ONTC asserted or could have asserted were payable prior to execution of this Restated Agreement.

4

b. BAT Settlement Payment.

(i) Effective as of July 6, 2001 and continuing through the Amended Term, APS will calculate its BAT Settlement Payment amount using the following formula:

BAT Settlement Payment =

[ (R * AI * Net KWhrs) less (Deductions) less (10% Standard Deduction) ] * 5%

Where R = $.0256 / KWhr.

Where Net KWhrs = APS’ share of actual net kilowatt hours generated from the Plant during the quarterly period.

Where Deductions = (1) Salaries and/or other compensation paid to members of the Navajo Nation; (2) Purchases of Navajo goods and services; and (3) Any payment made to the government of the Navajo Nation, except for the BAT Settlement Payment paid pursuant to this Restated Agreement and any penalties or fines.

Where Standard Deduction = an amount equal to the greater of ten percent of (R * AI * Net KWhrs) or $125,000.00.

As set forth on Exhibit C, APS will include in its Operating Report provided to the ONTC a statement of actual net generation for each quarter.

Where AI = an adjustment calculated in the 3^rd Quarter of each year based upon a 5-year rolling average of Producer Price Index data published by the Bureau of Labor Statistics. Annual adjustments shall be cumulative, i.e., the total current year adjustment shall be equal to the incremental current year adjustment multiplied by the previous year’s adjustment. The incremental adjustment shall be calculated utilizing the following methodology:

AI = (75% * Cost Index) plus (25% * Revenue Index).

Where Cost Index =

42.3% *	Bituminous Coal and Lignite: West (BLS Series PCU1211#214)
plus	0.9% * Natural Gas(BLS Series PCU1331#A2)
plus	7.6% * Other Heavy Construction (BLS Series PCUBHVY#)
plus	49.2% * Unit Labor Costs: Non-Farm Business (BLS Series PRS85006112)

Where Revenue Index =

65.2%	* Electric Power and Natural Gas Utilities, Other, Mountain (BLS Series PCU4981#148)
plus	34.8% * Electric Power and Natural Gas Utilities, Other, Pacific (BLS Series PCU4981#149)

5

If any of the BLS indices used in this calculation are discontinued, the Parties shall mutually agree upon an equivalent substitute BLS index. The Parties agree that, beginning January 1, 2002, the Bituminous Coal and Lignite: Surface Mining (BLS Series PCU1211#1) will be substituted into the calculation in place of Bituminous Coal and Lignite: West (BLS Series PCU1211#214).

A calculation of AI for the 3^rd Quarter 2001 through the 2^nd Quarter 2002 BAT Settlement Payments is attached as Exhibit B. The 5-year average of index data for 1996 through 2000 is used to develop this initial adjustment.

Each subsequent annual adjustment will be made for the 3^rd Quarter BAT Settlement Payment using the 5-year rolling average of index data through the end of the previous year.

A sample calculation of AI for the 3^rd Quarter 2002 through 2^nd Quarter 2003 BAT Settlement Payments using estimated data is included in Exhibit B. Calculations in subsequent years will follow this same formula.

(ii) APS will make its BAT Settlement Payments on a quarterly basis, with payments due 45 days after the end of each calendar quarter. APS will, at the time of making such payments, provide to the ONTC an Operating Report containing the following information used to calculate APS’ BAT Settlement Payment:

(a) APS revenue requirement, as adjusted by AI;

(b) Net KWhrs for the quarter;

(c) Deductions as defined above; and

(d) Standard Deduction.

The format for the Operating Report is set forth in Exhibit C.

(iii) Interest on any late payment of a BAT Settlement Payment will be computed from the date the BAT Settlement Payment was first due to the date such payment is received by the ONTC. The rate of interest on any late payments will be equal to the rate then being used by the Internal Revenue Service for an underpayment of taxes by an individual. If APS fails to timely pay the BAT Settlement Payment, APS will pay an additional amount equal to 5% of the BAT Settlement Payment due. For each full month the payment is overdue, APS will pay an additional amount equal to 0.5% of the amount of its BAT Settlement Payment; provided, however, that the maximum additional amount that APS will be required to pay for the failure to timely pay shall not exceed 10% of the BAT Settlement Payment amount due. If APS fails to timely provide to the ONTC an Operating Report required by this Restated Agreement, APS will pay an additional 5% of its BAT Settlement Payment for each month or fraction thereof that the Operating Report has not been provided to the ONTC; provided, however, that the minimum additional amount to be paid for APS’ failure to timely provide such Operating Report will be $50 and the maximum additional amount will not exceed twenty-five percent (25%) of APS’ BAT Settlement Payment for that period. For good cause shown, the ONTC may in its discretion relieve APS from all or part of the requirements imposed under this Section 2.b(iii).

6

(iv) The ONTC expressly agrees that APS is hereby released from any obligation and will not be required or requested to make any other payment with respect to any other amounts that the ONTC asserted or could have asserted were payable prior to execution of this Restated Agreement.

2. Releases.

a. APS hereby releases and forever discharges the ONTC, its predecessors, successors, affiliates, and assigns, of and from any and all claims, demands, damages, actions, causes of action, or suits of whatsoever kind and nature, existing as of the Effective Date of this Restated Agreement, whether now known or unknown to the Parties, or whether asserted or unasserted, related, either directly or indirectly, to any and all PIT and BAT tax assessments and taxes, and interest and penalties thereon, allegedly owed by the ONTC, its predecessors, successors, affiliates, and assigns, to APS arising from APS’ ownership interests or operation of the Facilities.

b. The ONTC hereby releases and forever discharges APS, its predecessors, successors, affiliates, and assigns, of and from any and all claims, demands, damages, actions, causes of action, or suits of whatsoever kind and nature, existing as of the Effective Date of this Restated Agreement, whether now known or unknown to the Parties, or whether asserted or unasserted, related, either directly or indirectly, to any and all PIT and BAT tax assessments and taxes, and interest and penalties thereon, allegedly owed by APS, its predecessors, successors, affiliates, and assigns, to the ONTC or Navajo Nation arising from APS’ ownership interests or operation of the Facilities.

c. The ONTC expressly covenants that it will not seek to apply or assess the Navajo Sales Tax, approved by the Navajo Nation Council pursuant to Resolution No. CO-84-01 on October 18, 2001 (as amended), with respect to any electricity generated at, from or by the Plant except for retail sales of electricity to persons who purchase electricity for that person’s own use, including use in that person’s trade or business and not for resale, redistribution or retransmission, within the Navajo Nation.

3. Case Closure.

The Parties agree that the following cases shall be closed:

Possessory Interest Tax: Case No. 01-042

Business Activity Tax: Case No. 01-056

7

4. Preservation of Rights.

It is understood and agreed that this is a settlement of disputed claims, whether asserted or unasserted, and that nothing contained herein shall be construed as an admission of liability, guilt, or wrongdoing by or on behalf of any of the undersigned Parties, all such liability, guilt, or wrongdoing being expressly denied. The Parties acknowledge and agree that this Restated Agreement shall not prejudice or limit in any way the rights or contentions of any Party. The Parties further agree that this Restated Agreement shall not in any way be deemed a waiver or amendment of any provisions of any other agreement between the Navajo Nation, APS and/or any of the Participants, including but not limited to the Leases and Grants. This Restated Agreement, and the actions of the Parties contemplated hereunder, are not intended, nor shall they be deemed, to constitute any waiver, consent or admission with respect to the existence or lack of regulatory, taxing, or adjudicatory authority or jurisdiction of the Navajo Nation or the ONTC over the Facilities or any Party hereto.

5. Enforcement and Judicial Review.

a. Neither Party shall commence any judicial or administrative action challenging the validity of this Restated Agreement or any Party’s authority to enter into it. Any commencement of such an action by a Party shall constitute a material breach of this Restated Agreement by that Party.

b. Challenge to Validity of the Restated Agreement.

(i) If the ONTC, or any of its representatives, officers, employees, departments or agents (a) commences any judicial or administrative action challenging this Agreement or the ONTC’s authority to enter into it, or (b) otherwise in any manner invalidates or breaches this Restated Agreement or takes any action contrary to this Restated Agreement, APS may, in its sole discretion, elect to seek specific performance of or terminate this Restated Agreement. If the ONTC, or any of its representatives, officers, employees, departments or agents, repeals the PIT or BAT and enacts a replacement tax that the ONTC seeks to assert against APS or the Facilities, APS may terminate this Restated Agreement. The ONTC agrees and recognizes that if APS terminates this Restated Agreement, APS shall have no further obligation or liability to make any Settlement Payments from the date of termination forward. The ONTC further agrees and recognizes that in such circumstance, APS has preserved its rights to contest the jurisdiction of the ONTC or the Navajo Nation to assert or assess any taxes against APS with respect to the Facilities, APS’ activities at the Facilities, or with respect to any other properties or activities within the Navajo Nation.

8

(ii) If APS, or any of its representatives, officers, employees, departments, or agents (a) commences any judicial or administrative action challenging this Restated Agreement or APS’ authority to enter into it, or (b) otherwise in any manner invalidates or breaches this Restated Agreement or takes any action contrary to this Restated Agreement, the ONTC may, in its sole discretion, elect to seek specific performance of or terminate this Restated Agreement. APS agrees and recognizes that, if the ONTC elects to terminate this Restated Agreement, the ONTC has preserved its rights to assert jurisdiction to assess taxes against APS from and after the date of termination with respect to the Facilities, APS’ activities at the Facilities, or with respect to any other properties or activities of APS within the Navajo Nation. If the ONTC elects to terminate this Restated Agreement, the ONTC shall be under no further obligation to accept Settlement Payments in satisfaction of APS’ obligations.

(iii) If any person or entity not a Party to this Restated Agreement or the Navajo Nation, or any of their representatives, officers, employees, agencies, departments or agents, commences any judicial, administrative or other action challenging in any way the Restated Agreement’s validity, the Parties shall jointly request that the court, tribunal, agency, or official before which the action is pending dismiss the action. If the action is not dismissed, either Party may file an appropriate responsive pleading, or otherwise act as reasonably necessary to respond to the action or to otherwise protect such Party. If any person, including the Navajo Nation or ONTC, brings an action or proceeding to assert or challenge the jurisdictional authority of the Nation or ONTC to tax the Facilities or activities at the Facilities with respect to such other person other than APS, each Party agrees not to rely on any ruling in such action or proceeding for purposes of challenging the validity of this Restated Agreement as long as the other Party is not in material breach hereof.

(iv) If any court, tribunal, agency or official determines that this Restated Agreement is non-binding on the ONTC or the Navajo Nation, APS may elect to terminate this Restated Agreement, and if so terminated, APS shall have no further obligation or liability to make any Settlement Payments from the date of termination forward. The ONTC agrees and recognizes that in such circumstance APS has preserved its rights to contest the jurisdiction of the Navajo Nation and ONTC to assert or assess any taxes against APS with respect to the Facilities, APS’ activities at the Facilities, or with respect to any other properties or activities within the Navajo Nation.

9

(v) If any court, tribunal, agency or official determines that this Restated Agreement is non-binding on APS, the ONTC may elect to terminate this Restated Agreement, and if so terminated, APS agrees and recognizes that in such circumstance, the ONTC has preserved its rights to assert jurisdiction to assess any taxes against APS with respect to the Facilities, APS’ activities at the Facilities, or with respect to any other properties or activities within the Navajo Nation.

c. Other Taxes. Nothing in this Restated Agreement affects the rights, if any, of (i) the Navajo Nation or ONTC to seek to enforce taxes other than the Sales Tax (except as otherwise provided in Section 2(c) above), PIT or BAT on APS or the Facilities or (ii) APS to challenge any such action by the Navajo Nation or ONTC, including when permitted by federal law, bringing such an action in federal court.

d. Enforcement of the Restated Agreement. Enforcement of this Restated Agreement by either Party shall be pursuant to this Restated Agreement and not pursuant to any Navajo Nation or other law independent of this Restated Agreement. Nothing in this Restated Agreement shall or may be deemed to limit a Party’s right to seek enforcement of this Restated Agreement or defend any claim in federal or tribal court where otherwise permitted by law. Nothing in this Restated Agreement shall or may be deemed as a consent to federal or tribal court jurisdiction by either Party.

6. Assignment.

APS may transfer or assign, without the consent of the Navajo Nation or ONTC, all or any portion of its interests and obligations under this Restated Agreement to any parent, subsidiary, affiliate or successor in interest of APS by merger, acquisition, or consolidation or to any other current or future owner of the Facilities, provided that the assignee assumes in writing all of APS’ obligations under this Restated Agreement.

7. Representations.

Each Party represents and warrants as of the Effective Date of this Restated Agreement as follows:

a. It has full legal right, power and authority to execute, deliver and perform this Restated Agreement;

b. It has taken all appropriate and necessary action to authorize the execution, delivery and performance of this Restated Agreement;

10

c. It has obtained all consents, approvals and authorizations necessary for the valid execution and delivery of this Restated Agreement;

d. This Restated Agreement constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms, except as such enforceability may be limited by applicable bankruptcy or insolvency laws or by limitation upon the availability of equitable remedies;

e. It is not in violation of any applicable law promulgated or judgment entered by any federal, state, local or other governmental body, which violations, individually or in the aggregate, would adversely affect the performance of its obligations under this Restated Agreement; and

f. The execution, delivery and performance by it of this Restated Agreement, the compliance with the terms and provisions hereof and the carrying out of the transactions contemplated hereby, (i) do not conflict with and will not conflict with or result in a breach or violation of any of the terms and provisions of its organizational documents, and (ii) to the best of its knowledge, do not conflict with and will not conflict with or result in a breach or violation of any of the terms and provisions of any law, rule or regulation, or any order, writ, injunction, judgment or decree by any court or other governmental body against it or by which it or any of its properties is bound, or any loan agreement, indenture, mortgage, note, resolution, bond or contract or other agreement or instrument to which it is a party or by which it or any of its properties is bound, or constitute or will constitute a default thereunder or will result in the imposition of any lien upon any of its properties.

8. Successors and Assigns.

This Restated Agreement shall be binding on and inure to the benefit of the Parties hereto and their successors and assigns.

9. Entire Agreement.

Except for any separate agreement of the Parties settling disputed claims related to applicability of the BAT to certain transmission and distribution facilities within the Navajo Nation, this Restated Agreement reflects the entire agreement of the Parties relating to taxation of the Facilities and no other agreement written or oral shall be used to effect any changes of the provisions retained herein. No amendment of this Restated Agreement shall be valid unless in writing and signed by all Parties.

11

10. Counterparts.

This Restated Agreement may be signed in counterparts, each of which shall be deemed an original. Facsimile signatures shall be as valid as original signatures until each Party receives a fully signed counterpart with original signatures. Each Party shall provide the other Party with original signatures so that each Party shall have a fully signed counterpart within five business days after the date of the last signature.

12

11. Relationship of Parties.

Nothing herein may be construed to create an association, joint venture, trust, or partnership, or to impose a trust or partnership covenant, obligation or liability on or with regard to any one or more of the Parties.

12. Severability.

Subject to the provisions of and except as otherwise provided in Section 5, Enforcement and Judicial Review, of this Restated Agreement, if any term or condition of this Restated Agreement is held to be invalid, void, or unenforceable by any court or tribunal of competent jurisdiction, that holding shall not affect the validity or enforceability of any other term or condition of this Restated Agreement, unless either Party determines in its sole discretion that enforcing the balance of the Restated Agreement would deprive that Party of a fundamental benefit of its bargain.

13. Adjustment of PIT and BAT Settlement Payment Amounts; Termination.

a. One year prior to the expiration of the Amended Term, the Parties shall commence good faith negotiations to establish PIT and BAT Settlement Payment amounts for APS to run concurrently with any extension of the Leases and Grants. If the Parties are not able to reach agreement upon new PIT and BAT Settlement Payment amounts before expiration of the Amended Term, the Parties will either continue this Restated Agreement in effect with the PIT and BAT Settlement Payment amounts set forth in Section 1 above, or either Party may elect to terminate this Restated Agreement.

b. The Parties recognize and agree that, upon termination or expiration of this Restated Agreement for any reason, (i) each Party has preserved all of its rights and arguments regarding the question of the jurisdictional authority of the Navajo Nation and ONTC to tax the Facilities and/or APS and its successors and assigns based on ownership interests in and operation of the Facilities; (ii) this Restated Agreement shall not in any way be deemed a waiver or amendment of any provisions of any agreement between the Navajo Nation, APS and/or any of the Participants, including but not limited to the Leases and Grants; and (iii) neither Party may assert any claim, demand, damages, action, cause of action, or suit of whatsoever kind and nature, whether known or unknown to the Parties, or whether asserted or unasserted, related, either directly or indirectly, to any and all PIT and BAT tax assessments and taxes, and interest and penalties thereon, that arose or may have arisen while this Restated Agreement was in effect.

13

14. No Third Party Beneficiaries.

Nothing herein, either express or implied is intended or may be construed to confer upon or to give to any person or entity other than the Parties any rights or remedies under or by reason of this Restated Agreement.

15. Limited Responsibility.

The Parties acknowledge and agree that it is their mutual intent that the obligations, representations, warranties and undertakings under this Restated Agreement or as a result of the transactions contemplated by this Restated Agreement are limited to only those expressly set forth herein, and not enlarged by implication, creation of law, or otherwise.

16. Survival.

The provisions of Sections 2(a) and (b), 4, 7 and 13.b of this Restated Agreement survive expiration or termination of this Restated Agreement. Provided that the Restated Agreement remains in effect through the Amended Term, APS’ obligation to make the calendar year 2041 PIT Settlement Payment specified in this Restated Agreement and APS’ obligation to make BAT Settlement Payments for any periods prior to expiration or termination of this Restated Agreement also shall survive expiration or termination of this Restated Agreement.

17. Notices.

Notices shall be deemed to have been given if in writing and (a) hand delivered, (b) delivered by a reputable overnight courier service (such as but not limited to FedEx and UPS), (c) mailed by certified or registered mail, return receipts requested, first class postage prepaid, or (d) transmitted by telecopy or electronic mail, followed within 24 hours by transmittal under option (a), (b) or (c) above addressed as follows:

If to ONTC:

President

The Navajo Nation

P.O. Box 9000

Window Rock, Arizona 86515

With a copy to:

Attorney General

Navajo Nation Department of Justice

P.O. Drawer 2010

14

Window Rock, Arizona 86515

Executive Director

Office of the Navajo Tax Commission

P.O. Box 1903

Window Rock, Arizona 86515

If to APS:

Arizona Public Service Corporation

400 North 5^th Street

Phoenix, Arizona 85004

Attn: Corporate Secretary

With a copy to:

Pinnacle West Capital Corporation

400 North 5th Street

Phoenix, Arizona 85004

Attn: Executive Vice President and General Counsel

or at such other address as the Parties may, from time to time, designate in writing. Service by overnight courier or mail shall be deemed made on the first business day delivery is attempted or upon receipt, whichever is earlier. Service by telecopy or electronic mail shall be deemed made upon confirmed transmission.

18. Effective Date; Effect of this Restated Agreement.

This Restated Agreement is effective upon the date when duly executed by both Parties (the “Effective Date”). It is the Parties’ intention that through the Effective Date of this Restated Agreement, the terms and conditions of the Original Agreement in effect at the date of execution of this Restated Agreement shall continue to govern the Parties’ rights and obligations thereunder. Upon and after the Effective Date of this Restated Agreement, the Parties’ right and obligations shall be governed by the terms and conditions of this Restated Agreement.

15

By signing, the undersigned certify that they have read and agreed to the terms of this Restated Agreement.

ARIZONA PUBLIC SERVICE COMPANY
By:
	Donald G. Robinson	Date
	President
NAVAJO NATION
By:
	Martin Ashley, Executive Director	Date
	Office of the Navajo Tax Commission
APPROVED:
By:
	Louis Denetsosie, Attorney General		Date
	Navajo Nation Department of Justice

16

SETTLEMENT AND CLOSING AGREEMENT

EXHIBIT A

REPORT FOR PIT SETTLEMENT PAYMENT

1.	Company Name:
2.	Mailing Address:
3.	Contact Name:                                                   Contact Phone Number:
4.	Name of Power Generating Facility:
5.	Name of Plant Operator:
6.	Location of Facility/Power Plant (Sec. Twp, Rng):
7.	Term of Lease:                                                   Lease Expiration Date:
8.	Percent Participation of Total Plant:
9.	Number of Units:

		Production (KWH or MWH)		Year Placed
Unit#	Capacity (KWH, MWH)	for Calendar Year	% Interest	in Service
		Total

10.	Type of fuel in use for each unit (coal, gas, etc.):
11.	What is the cost per ton of coal used and purchased by the plant:
12.	Total area of plant site including cooling ponds, coal storage, ash disposal area (acres):
13.	Operating cost($):                     ($/KWH)                          Capital cost($):                         ($/KWH)
14.	Original cost of entire plant($):                                                                                                                                                        (Original cost means the actual cost of the asset before depreciation/Refer to the attached New Mexico Property Tax Report)
15.	Material & Supplies($):                                                       Construction Work In Progress($):                                              (Refer to the attached New Mexico Property Tax Report)        (Refer to the attached New Mexico Property Tax Report)
16.	Book value of entire plant($)                                                                                                                                        (Book value means the original cost less depreciation./Refer to the attached New Mexico Property Tax Report.)
17.	What is the % rate of return allowed by the state regulatory agency?                                                                                       (Only for those companies whose customer rates are regulated by a corporation commission or public utilities commission)

**Note**

** The amounts reported for items #13 through #16 are reflective of each individual Participant’s ownership share and are not intended to depict Total Plant **

Transmission & Distribution Property Information

1. Transmission Lines

			Width of Right-
KV Rating	Year Built	Miles	of-Way	Acres
2. Distribution System
				Width of Right-
Chapter	Urban Meters	Rural Miles	KV Rating	of-Way
3. Substations & Switching Stations
		Transformer
Name	Voltage Rating	KVA	Year Built	Acres

Additional Information for Operating Report

1. Copy of the previous calendar year annual report or the 10-K filed with the Securities and Exchange Commission

2. Copy of the previous calendar year FERC Form No. 1 (Only for those companies that are required to file this report with FERC)

3. Copy of the New Mexico Property Tax Report

Exhibit B

Calculation of AI (BAT Index) for 2001 and 2002

Price Indexes: Year-to-Year Change

	Electric Power -						Bituminous									Unit Labor
	Other -			Electric Power -			Coal and						Heavy			Cost: Non-Farm
	Mountain			Other - Pacific			Lignite: West			Natural Gas			Construction			Business
1996		105.1	%		99.3	%		102.8	%		136.9	%		101.9	%		100.5	%
1997		101.8	%		102.4	%		99.3	%		111.5	%		101.8	%		100.9	%
1998		100.0	%		100.4	%		96.4	%		82.5	%		99.0	%		102.7	%
1999		99.6	%		100.1	%		98.4	%		108.8	%		101.1	%		102.0	%
2000		99.9	%		104.9	%		97.9	%		170.4	%		103.7	%		103.1	%
2001 (estimated)		105.2	%		111.1	%		103.0	%		110.7	%		99.9	%		103.8	%
2002 (estimated)		99.2	%		97.9	%		99.1	%		52.1	%		97.7	%		100.4	%

Note: Each entry is calculated as the annual average of the appropriate index for the current year divided by the annual average of the same index for the previous year.

BAT Index Calculation

	Revenue Index			Cost Index			Total BAT Index			5-Year Average
1996		103.1	%		101.9	%		102.2	%		—
1997		102.0	%		100.4	%		100.8	%		—
1998		100.1	%		99.6	%		99.7	%		—
1999		99.8	%		100.5	%		100.3	%		—
2000		101.7	%		101.5	%		101.5	%		100.9	%
2001 (estimated*)		107.3	%		103.2	%		104.2	%		101.3	%
2002 (estimated*)		98.7	%		99.2	%		99.1	%		101.0	%

Note:

Revenue Index =

65.24% * (BLS Index: Electric Power — Other — Mountain)

plus 34.76% * (BLS Index: Electric Power — Other — Pacific)

Cost Index =

42.29% * (BLS Index: Bituminous Coal and Lignite: West)

plus 0.86% * (BLS Index: Natural Gas)

plus 7.58% * (BLS Index: Heavy Construction)

plus 49.27% * (BLS Index: Unit Labor Costs: Non-Farm Business)

Total BAT Index = (75% * Cost Index) plus (25% * Revenue Index)

AI Calculation

AI for BAT Settlement Payments 2001 Q3 through 2002 Q2 =
Average of BAT Index for 1996-2000 =	100.9	%
AI (estimated*) for BAT Settlement Payments 2002 Q3 through 2003 Q2 =
AI for 2001 multiplied by average of BAT Index for 1997-2001 =
[ 100.9%* 101.3% ] =	102.2	%	estimated	*
AI for BAT Settlement Payments 2003 Q3 through 2004 Q2 =
AI for 2002 multiplied by average of BAT Index for 1998-2002 =
[ 100.9%* 101.3%* 101.0% ] =	103.2	%	estimated	*
AI for subsequent year BAT Settlement Payments will follow the same formula.

Note:

* The AI for the 2002 BAT Settlement Payments is estimated using actual BLS data through November 2001 and estimated data for December 2001. This calculation should be updated when complete 2001 BLS data is made available. The AI for the 2003 BAT Settlement Payments is a sample calculation using only data available through March 2002.

Exhibit B (continued)

BLS Price Index Data for AI Calculation

Series Id: PCU1211#214

Industry: Bituminous coal and lignite

Product: West

Base Date: 8112

Year	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		118.7		119.2		119.8		118.5		119.5		122.3		126.4		122.5		119.4		121.6		120.8		120.4			120.8
1996		124.7		125.8		127.6		121.6		127.6		120.9		121.1		126.1		126.2		123.9		121.3		122.4			124.1
1997		121.6		122.6		126.1		129.7		125.8		122.8		125.3		121.7		119.5		121.3		121.9		119.8			123.2
1998		113.8		120.0		118.7		121.8		122.0		120.4		117.4		117.5		118.2		117.0		118.2		120.1			118.8
1999		116.9		118.6		118.5		119.4		116.0		116.7		116.1		115.1		117.3		116.4		115.0		116.6			116.9
2000		114.6		114.7		115.7		113.3		114.6		114.0		115.9		112.7		113.1		114.9		114.1		115.1			114.4
2001		114.6		113.2		114.6		115.9		118.0		116.3		120.1		121.4		119.3		121.5		120.2		[ILLEGIBLE	]		[ILLEGIBLE	]

Series Id: PCU1221#1

Industry: Bituminous coal & lignite surface mining

Product: Unprepared (raw) bituminous coal and lignite shipped from surface operations

Base Date: 0112

2002 [ILLEGIBLE] [ILLEGIBLE] [ILLEGIBLE] [ILLEGIBLE]

New Coal Index (see Notes, below)

2002 [ILLEGIBLE] [ILLEGIBLE] [ILLEGIBLE] [ILLEGIBLE ] 

Series Id: PCU1331#A2

Industry: Crude petroleum, natural gas and natural gas liquids

Product: Natural gas

Base Date: 8406

Year	Jan			Feb			Mar			Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		68.4			62.9			61.3			62.3		63.2		64.8		63.2		56.0		57.1		59.7		63.0		68.9			62.6
1996		78.4			90.7			80.6			87.2		82.7		74.1		82.0		82.9		72.0		70.7		94.6		132.2			85.7
1997		149.9			112.6			73.8			71.0		78.6		83.4		80.6		81.8		91.0		108.8		119.6		95.3			95.5
1998		85.4			76.9			81.2			84.7		85.0		76.9		83.7		77.1		65.6		72.9		78.1		78.3			78.8
1999		70.2			67.6			63.0			69.5		85.9		83.6		86.4		98.0		107.9		97.8		114.2		84.6			85.7
2000		92.1			98.4			99.3			107.8		115.8		159.9		160.2		142.7		166.7		189.5		173.8		247.4			146.1
2001		370.1			246.5			202.8			207.3		191.3		144.2		113.8		113.6		87.4		68.5		107.2		[ILLEGIBLE	]		[ILLEGIBLE	]
2002		[ILLEGIBLE	]		[ILLEGIBLE	]		[ILLEGIBLE	]																					[ILLEGIBLE	]

Series Id: PCUBHVY#

Industry: Other heavy construction

Product: Other heavy construction

Base Date: 8606

Year	Jan			Feb			Mar			Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		128.1			128.6			129.0			129.9		129.9		130.1		130.3		130.4		130.5		130.1		130.3		130.5			129.8
1996		130.6			130.4			131.0			132.0		133.0		133.0		132.3		132.4		132.9		132.9		133.3		133.6			132.3
1997		134.0			134.4			134.5			134.8		135.2		135.0		134.9		135.0		134.9		134.5		134.4		134.0			134.6
1998		133.6			133.3			133.3			133.7		133.8		133.6		133.9		133.5		133.4		133.1		132.6		131.9			133.3
1999		132.4			132.2			132.6			133.7		134.2		134.5		135.7		136.2		136.4		136.1		136.3		136.9			134.8
2000		137.8			139.0			140.0			139.5		139.3		140.5		140.3		139.8		140.8		140.6		140.4		139.7			139.8
2001		140.1			140.3			139.9			140.5		141.9		141.7		139.7		139.7		140.4		137.9		137.1		[ILLEGIBLE	]		[ILLEGIBLE	]
2002		[ILLEGIBLE	]		[ILLEGIBLE	]		[ILLEGIBLE	]																					[ILLEGIBLE	]

Exhibit B (continued)

BLS Price Index Data for AI Calculation

Series Id: PCU4981#148

Industry: Electric power and natural gas utilities

Product: Other — Mountain

Base Date: 9012

Year	Jan			Feb			Mar			Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		112.0			111.9			110.4			110.4		110.5		114.9		115.1		115.1		115.2		115.2		112.0		111.8			112.9
1996		111.7			111.8			110.3			111.5		120.0		123.6		123.7		123.7		123.6		122.9		120.2		120.2			118.6
1997		119.9			118.9			118.6			118.6		121.5		122.9		122.8		122.8		122.8		122.8		118.4		118.2			120.7
1998		118.4			119.1			119.1			119.1		122.0		123.3		122.5		122.2		122.2		122.2		118.9		118.9			120.7
1999		118.3			118.2			118.0			118.0		120.7		122.1		122.0		122.4		122.4		122.1		119.3		119.3			120.2
2000		119.2			119.1			118.2			118.2		118.2		121.9		121.6		121.9		122.1		122.2		119.3		119.8			120.1
2001		119.9			120.0			124.4			124.7		127.6		129.2		129.0		130.0		130.1		129.7		126.3		[ILLEGIBLE	]		[ILLEGIBLE	]
2002		[ILLEGIBLE	]		[ILLEGIBLE	]		[ILLEGIBLE	]																					[ILLEGIBLE	]

Series Id: PCU4981#149

Industry: Electric power and natural gas utilities

Product: Other — Pacific

Base Date: 9012

Year	Jan			Feb			Mar			Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		103.6			103.6			102.2			101.5		103.4		113.4		113.5		113.5		113.2		101.5		103.0		103.0			106.3
1996		102.6			102.7			100.3			101.2		103.1		111.2		111.6		111.6		111.5		102.6		104.1		104.1			105.6
1997		104.6			104.7			102.6			104.1		105.5		113.3		114.2		114.2		116.0		105.8		105.9		106.0			108.1
1998		105.8			105.4			103.5			103.5		106.2		114.5		114.6		114.5		115.5		106.0		106.1		106.1			108.5
1999		106.1			105.9			102.5			102.6		104.4		113.8		114.2		114.0		116.1		107.9		107.9		107.0			108.5
2000		106.9			106.9			105.8			106.1		106.9		117.5		121.2		123.4		123.3		115.8		114.9		117.5			113.9
2001		126.0			120.9			122.4			114.0		114.8		134.6		136.0		136.2		136.1		126.5		126.2		[ILLEGIBLE	]		[ILLEGIBLE	]
2002		[ILLEGIBLE	]		[ILLEGIBLE	]		[ILLEGIBLE	]																					[ILLEGIBLE	]

Series Id: PRS85006113

Duration: index, 1992 = 100

Measure: Unit Labor Costs

Sector: Nonfarm Business

Year	Qtr1			Qtr2		Qtr3		Qtr4		Ann Avg
1995		103.1			103.6		104.0		104.0		103.7
1996		103.6			103.7		104.5		104.9		104.2
1997		105.2			104.5		104.7		106.1		105.1
1998		106.7			108.0		108.7		108.6		108.0
1999		109.0			110.5		111.1		110.2		110.2
2000		112.1			112.5		114.0		115.8		113.6
2001		117.2			118.0		118.7		117.9		118.0
2002		[ILLEGIBLE	]								[ILLEGIBLE	]

Notes:

The PCU1211 series was discontinued at the end of 2001. The new series, PCU 1221#1 (which started at 100.0 in Dec. 2001), will be substituted in the AI calculation beginning Jan. 2002. Monthly values for the coal index will be calculated by taking the value of the old coal index on Dec. 2001, 118.4, and multiplying it by the value of the new coal index in each month, then dividing by 100. For example, in Jan. 2002, the value for the coal index used in the AI calculation will be 118.4 * 96.7 / 100 = 114.5.

The PPI data is updated monthly and made available at the BLS website: http://data.bls.gov/labiava/outside.isp?survey=pc

The labor cost data is updated quarterly and is also available at the BLS website: http://www.bls.gov/lpc/home./htm

Shaded entries denote preliminary BLS data.

Settlement and Closing Agreement

Exhibit C

Operating Report

Line No.
1. Revenue Requirement	$	X.XXXX /KWhr
2.	x	AI
3. Subtotal	$	X.XXXX
4.	x	Net KWhrs
5. Subtotal	$	XXXXX
Less Deductions
6. Salaries and/or other compensation paid to members of the Navajo Nation (See Supplemental Schedule I)	$	XXXXX
7. Purchases of Navajo goods and Services (See Supplemental Schedule II)	$	XXXXX
8. Payments made to the Navajo Nation government (See Supplemental Schedule III)	$	XXXXX
9. Standard Deduction (The greater of $125,000 or 10% of line 5.)	$	XXXXX
10. Total Deductions	$	XXXXX
11. BAT Settlement Payment Base (Line 5 less Line 10)	$	XXXXX
12. BAT Settlement Payment Rate	x	5	%
13. BAT Settlement Payment	$	XXXXX

SETTLEMENT & CLOSING AGREEMENT

EXHIBIT C

SUPPLEMENTAL SCHEDULE I

SALARIES, WAGES, AND OTHER COMPENSATION PAID TO NAVAJOS Page          of         

Company Name (Employer) Quarter Ended

	1. Employee	Navajo Census	2. Salaries or	3. Other Compensation	4. Total of Column 2
I.	Name	Number	Wages Paid	(e.g. fringe benefits)	and Column 3
II.	Total from any additional pages
	Total Salaries and Wages Paid, total column 2
	Total Other Compensation (e.g. fringe benefits), total column 3
III.	Total Salaries, Wages, and Other Compensation, total Col. 4

SETTLEMENT & CLOSING AGREEMENT

EXHIBIT C

SUPPLEMENTAL SCHEDULE II

Purchases of Navajo Goods & Services Page          of         

Company Name (Employer) Quarter Ended

Part A — Detail Purchases of Navajo Goods

Type of Goods Purchased	Vendor Name and Address	Amount
	Total amount

Part B — Detail of Purchases of Navajo Services

Type of Services Purchased	Vendor Name and Address	Amount
	Total amount

SETTLEMENT & CLOSING AGREEMENT

EXHIBIT C

SUPPLEMENTAL SCHEDULE III

Detail of Payments Made to the Navajo Nation Government Page          of         

Company Name (Employer) Quarter Ended

Detail of Payments Made to the Navajo Nation Government

Type of Payment	Payee	Date of Payment	Amount
	Total amount

Restated and Amended Settlement and Closing Agreement

Exhibit D — Sample PIT Calculations

Assumptions:

Original Cost of Facilities on Navajo Nation:

Property Group	Original Cost*
Units 1 - 3		400,000,000
Units 4 - 5		200,000,000
Common		100,000,000
T & D		100,000,000
TOTAL		800,000,000
Current PIT Settlement Payment:	$	6,342,600
Salvage Value = Original Cost x 5%
In-lieu-of-Tax Rate for Salvage = 3%
Sample Calculation for Shut Down of Units:
Assume Permanent Shut Down of Units 1 - 3
Salvage Value of Units 1 - 3 = Original Cost x 5%
$400M x 5% =		20,000,000
In-lieu-of tax on Units 1 - 3 = Salvage Value x In-lieu-of Tax Rate
$20M x 3% =		600,000
Calc. of PIT for Remaining Property in Service:
Original Cost of Remaining Property In Service/Total Original Cost
$400M/800M =		50.00	%
PIT on Remaining Property
0.50 x $6,342,600 =	$	3,171,300
New PIT After Permanent Shut Down of Units 1 - 3:
In-lieu-of tax + PIT on Remaining Property =	$	3,771,300
Sample Calculation if APS Adds a Unit:
Assume APS Adds $1B Unit
Calculation of Increase Factor = Current PIT Settlement Payment/Total Original Cost
$6,342,600/$800M =		0.7928	%
Calculation of PIT on New Unit = Original Cost of New Unit x Factor
$1B x 0.007928 =	$	7,928,250
Existing PIT =	$	6,342,600
New PIT After Addition of Unit	$	14,270,850

* Original Costs are not actual original costs, these costs are for illustration purposes only.

EX-10.2

Exhibit 10.2

AMENDMENT AND SUPPLEMENT NO. 3

TO

SUPPLEMENTAL AND ADDITIONAL INDENTURE OF LEASE

BETWEEN

THE NAVAJO NATION

AND

ARIZONA PUBLIC SERVICE COMPANY,

EL PASO ELECTRIC COMPANY,

PUBLIC SERVICE COMPANY OF NEW MEXICO,

SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT,

AND

TUCSON ELECTRIC POWER COMPANY

Dated: March 7, 2011

AMENDMENT AND SUPPLEMENT NO. 3 TO

SUPPLEMENTAL AND ADDITIONAL INDENTURE OF LEASE

This Amendment and Supplement No. 3 to the Supplemental and Additional Indenture of Lease dated March 7, 2011 (this “Amendment”) is by and between the Navajo Nation (formerly known as The Navajo Tribe of Indians), acting through the Navajo Nation Council for and on behalf of the Navajo Nation (hereinafter referred to as the “Nation”), as lessor, and Arizona Public Service Company (“APS”), El Paso Electric Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, and Tucson Electric Power Company (formerly known as Tucson Gas & Electric Company) (hereinafter, collectively, together with their successors and assigns, referred to as the “Lessees,” and each individually referred to as a “Lessee”). The Nation and the Lessees are hereinafter collectively referred to as the “Parties.”

The Parties agree as follows:

1 BACKGROUND.

1.1 APS has leased certain premises from the Nation under that certain Indenture of Lease dated December 1, 1960 between APS and the Nation, as supplemented and amended by that certain Supplemental and Additional Indenture of Lease dated July 6, 1966, between the Nation, APS, and the other Lessees, as further supplemented and amended by that certain Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease dated April 25, 1985, between the Nation, APS and the other Lessees (the “1985 Lease Supplement”; and such Indenture of Lease, as supplemented and amended, the “1960 Lease”).

1.2 Lessees have leased certain premises from the Nation under that certain Supplemental and Additional Indenture of Lease dated July 6, 1966, between the Nation, Southern California Edison Company (“SCE”), and the Lessees, as supplemented and amended by the 1985 Lease Supplement (such Supplemental and Additional Indenture of Lease, as supplemented and amended, the “1966 Lease”).

1

1.3 The Parties desire to extend the respective terms of and otherwise amend the 1960 Lease and the 1966 Lease to reflect certain new terms and conditions.

1.4 The 1960 Lease and the 1966 Lease are amended only as set forth in this Amendment. To the extent, however, that there is any conflict between the 1960 Lease and this Amendment or the 1966 Lease and this Amendment, this Amendment shall govern.

1.5 This Amendment is not intended to and does not merge the leasehold estates of the 1960 Lease and the 1966 Lease, or the rights, liabilities, or obligations (collectively, “Rights”) of the Parties set forth in the 1960 Lease and the 1966 Lease. Further, in no event shall the Lessees (except for APS) have any Rights under the 1960 Lease or with respect to the leasehold estate demised to APS under the 1960 Lease. Rather, except for APS, all the Lessees’ Rights are limited only to the Four Corners Project, as set forth in the 1966 Lease.

2 DEFINITIONS.

2.1 “§ 323 Grant” or “§ 323 Grants” — One or more grants of rights-of-way and easements under the Act of February 5, 1948 (62 Stat. 17, 18, 25 U.S.C. §323-328), the Act of March 3, 1879 (20 Stat. 394, 5 U.S.C. § 485), as amended, and the Acts of July 9, 1832, and July 27, 1868 (4 Stat. 564, 15 Stat. 228. 25 U.S.C. §2) and such regulations promulgated thereunder, as are applicable, including 25 C.F.R. §1.2 and 25 C.F.R. Part 169.

2.2 “§ 323 Grant Land” — Has the meaning set forth in Section 5.2.

2

2.3 “Affiliate” — With respect to any Lessee hereto, any entity, including but not limited to a corporation, company, partnership, LLC/LLP or joint venture that directly or indirectly, through one or more intermediaries, controls, is controlled by, or is under common control with such Lessee. For purposes of this definition, the term “control” (including “controlled by” and “under common control with”) shall mean the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of an entity, whether through the ownership of voting securities, regardless of percentage by written contract, or otherwise.

2.4 “Annual Payment” — Except for (i) payments owed to the Nation under the existing Settlement and Closing Agreements that the Nation has executed with each individual Lessee (ii) the payments that will be owed to the Nation under the Settlement and Closing Agreements set forth in Section 14; (iii) the negotiation premium set forth in Section 3.4; and (iv) the payment set forth in Section 4.5, the total and sole payment that shall be made by (X) APS to the Nation, in consideration for the rights set forth in the 1960 Lease, including, but not limited to, (a) all leasehold rights, (b) the Existing § 323 Grants, and (c) the Renewed § 323 Grants; and by (Y) the Lessees to the Nation, in consideration for the rights set forth in the 1966 Lease, including, but not limited to, (a) all leasehold rights, (b) the Existing § 323 Grants, and (c) the Renewed § 323 Grants.

2.5 “Communication Sites” — The communication sites and related facilities identified within item 5 of Exhibit B.

2.6 “Existing § 323 Grants” — The § 323 Grants set forth on Exhibit B.

2.7 “Four Corners Project” — Has the meaning set forth in the 1966 Lease.

2.8 “Initial Four Corners Plant” — Has the meaning set forth in the 1966 Lease.

3

2.9 “Plan” — Has the meaning set forth in Section 7.1.

2.10 “Plant” — For convenience only, and not to merge the leasehold estates under the 1960 Lease and the 1966 Lease, a reference to the Initial Four Corners Plant and the Four Corners Project, respectively.

2.11 “Renewed § 323 Grants” — Has the meaning set forth in Section 4.2.

2.12 “Navajo Nation Lands” — Has the meaning set forth in the 1966 Lease for the term “Reservation Lands.”

2.13 “Secretary” — The Secretary of the United States Department of the Interior or his or her duly authorized designee, representative, or successor.

2.14 “Transmission Lines” — The electrical transmission lines and related facilities identified within items 3 and 4 of Exhibit B.

3 TERM.

3.1 This Amendment shall become effective (the “Amendment Effective Date”) upon the earlier of SCE’s sale of its interest in the Four Corners Project or July 6, 2016 (the “Amendment 2 Termination Date,” as defined in the Amendment and Supplement No. 2 to the Supplemental and Additional Indenture of Lease, attached as Exhibit A).

3.2 The Navajo Nation Council Resolution approving this Amendment, and signature by the Nation’s duly authorized representative, shall be deemed to be sufficient legal approval by the Nation of this Amendment.

3.3 The 1960 Lease and the 1966 Lease (and the Annual Payments payable thereunder) are extended to July 6, 2041, whether or not the Initial Four Corners Plant or the Four Corners Project are operating or the Renewed § 323 Grants are terminated.

4

3.4 The Nation will engage in good-faith negotiations for an additional extension of both the 1960 Lease and the 1966 Lease beyond 2041, provided that such negotiations begin no later than July 2029 and conclude by July 2031. Any mutual agreement to continue the negotiations beyond July 2031, which such negotiations are not successfully completed, will extend the term of both the 1960 Lease and the 1966 Lease equally beyond July 2041, provided that (i) the negotiation extension period shall not exceed three years; and (ii) APS with respect to the 1960 Lease and the Lessees with respect to the 1966 Lease shall pay the Nation a pre-negotiated premium (above the Annual Payment) for the period the negotiations are extended.

4 NATION’S CONSENT TO § 323 GRANTS BY SECRETARY FOR THE PLANT, TRANSMISSION LINES, AND COMMUNICATION SITES.

4.1 The Nation has previously consented to, and the Secretary has granted, the Existing § 323 Grants, and the renewal, extension or reissuance of each Existing § 323 Grant will be necessary.

4.2 The Nation consents and covenants to consent now, and for the terms of each of the 1960 Lease and the 1966 Lease (collectively, “Consents”), that the Lessees shall have the right to obtain, by grant from the Secretary, and the Nation Consents to the grant by the Secretary, of renewed, extended, or reissued § 323 Grants for the rights-of-way covered in the Existing § 323 Grants. (Such renewed, extended, or reissued § 323 Grants are referred to as the “Renewed § 323 Grants”).

4.3 The Nation and Lessees will cooperate fully with each other and the Secretary to obtain the Renewed § 323 Grants.

5

4.4 The Navajo Nation Council Resolution approving this Amendment shall be deemed to be sufficient legal approval by the Nation for the Renewed § 323 Grants. No further consideration shall be required by the Nation in order for the Secretary to issue the Renewed § 323 Grants.

4.5 The Lessees shall provide the Nation a copy of applications for the Renewed § 323 Grants, and each application shall be accompanied by a payment of no more than $800 per application.

4.6 The Existing § 323 Grants and the Renewed § 323 Grants shall be additional and supplementary to, separate and independent from, and not conditioned upon the leasehold rights leased to APS under the 1960 Lease and to the Lessees under the 1966 Lease; and a termination of either the 1960 Lease or the 1966 Lease for any reason shall not terminate any §323 Grant, and a termination of any § 323 Grant for any reason, shall not terminate the 1960 Lease or the 1966 Lease.

4.7 The Nation agrees to support the renewal, extension, or reissuance of the Existing § 323 Grants as categorically excluded under section 3.2A of the Bureau of Indian Affairs’ 2005 National Environmental Policy Act Handbook. If the Secretary determines that additional environmental impact analysis is required, the Nation hereby grants Lessees access to all Navajo Nation Lands necessary to complete such additional analysis. Lessees will work with the appropriate Navajo Nation agencies to effectuate any necessary access to any Navajo Nation Lands. The Nation also agrees to assist the Lessees in completing such analysis and to take reasonable actions to reduce the time and cost required to complete such analysis.

4.8 Except as set forth in the 1960 Lease, APS shall not change the voltages of the Transmission Lines without the Nation’s prior approval.

4.9 Under no circumstances shall any § 323 Grant be interpreted as granting a fee simple interest to the Lessees or any other property interest, except as set forth in the § 323 Grant.

6

5 ADDITIONAL TERMS REGARDING § 323 GRANTS FOR TRANSMISSION LINES.

5.1 The provisions of Section 5.2 through Section 5.7 and Section 10 and Section 12 below constitute a separate agreement between the Nation and APS. In no event shall any default, action or omission by APS under Section 5.2 through Section 5.7, Section 10, or Section 12 below have any effect on any other Parties’ rights, privileges, duties, obligations and liabilities under the remainder of this Amendment.

5.2 The Navajo Nation Lands subject to an Existing § 323 Grant or a Renewed § 323 Grant and pertaining only to the Transmission Lines shall hereinafter be referred to as “§ 323 Grant Land.”

5.3 The use of the § 323 Grant Land shall be strictly limited to constructing, reconstructing, replacing, repairing, operating and maintaining the Transmission Lines. Any other use of the § 323 Grant Land shall require the consent of the Nation. The consent of the Nation may be given, given upon conditions, or denied at the sole discretion of the Nation.

5.4 The Nation shall be under no obligation to forego the use of the § 323 Grant Land or any portion or lands burdened by the § 323 Grant Land, or to refrain from authorizing any use of said lands by any third party, including but not limited to, the exploration for and development and transportation of coal, oil, gas, or other natural resources located within or beneath said lands, except to the extent that such use physically interferes with the operation and maintenance of the Transmission Lines or interferes with the purposes of the § 323 Grants.

7

5.5 Upon the Nation’s proposed authorization of the use of the § 323 Grant Lands by any third party, which new use may occupy the § 323 Grant Lands or otherwise burden the § 323 Grant Lands, the Nation agrees to notify APS and commence good faith consultation with APS prior to the Nation’s final approval of said third party use. Prior to the Nation’s final approval, the Nation shall require the third party to enter into an agreement with APS, which agreement must be acceptable to APS, to indemnify, defend, and hold APS harmless from any and all liability arising from the third party’s use, interest, and activities within the § 323 Grant Land.

5.6 Five years prior to the expiration of a Renewed § 323 Grant, or as soon as practicable after any earlier termination of a Renewed § 323 Grant, APS and the Nation shall meet to discuss whether APS will leave in place all, some, or none of the Transmission Lines. If APS and the Nation cannot agree to terms regarding the disposition of one or more of the Transmission Lines, APS shall remove the Transmission Line(s) for which no agreement is reached, in accordance with the Lease and applicable laws and requirements, and shall leave the § 323 Grant Land in good condition. On the expiration date of a Renewed § 323 Grant, APS shall have ninety (90) days to peaceably and without legal process deliver the possession of the § 323 Grant Land, with or without the Transmission Lines, as the case may be. In the event a Renewed § 323 Grant is terminated early, APS shall have six months to peaceably and without legal process deliver the possession of the § 323 Grant Land for such terminated § 323 Grant, with or without the Transmission Lines, as the case may be. If delivery cannot be performed on or before such 90-day period or six month period, as the case may be, APS and the Nation shall commence good faith negotiations for compensation, fees or damages to be paid to the Nation for prospective periods of occupation, use, or burden of the § 323 Grant Lands.

8

5.7 Holding over by APS after the expiration or early termination of a Renewed § 323 Grant shall not constitute an extension/renewal thereof, or give APS any rights in or to the § 323 Grant Lands. Holding over after expiration or early termination of a Renewed § 323 Grant shall not give APS any rights via a Renewed § 323 Grant. Following expiration or early termination of a § 323 Grant, the act of applying for a § 323 Grant from the Secretary shall not give APS any rights to the § 323 Grant land.

6 NATION’S SUPPORT OF ENVIRONMENTAL REVIEWS AND § 323 GRANTS.

The Nation shall work with the Lessees to obtain the necessary regulatory approvals and to advocate on behalf of the Lessees in support of any National Environmental Policy Act, Endangered Species Act, or National Historic Preservation Act analyses; § 323 renewals or extensions; or any other requirements of the Department of the Interior (“DOI”) or the Nation that are prerequisites necessary to conduct the operations of the Plant, Transmission Lines, and Communication Sites. In its interactions with the DOI, the Nation shall support the interests of the Lessees and advocate positions that support the continued operations of the Plant, Transmission Lines, and Communication Sites.

9

7 EMPLOYMENT AT THE FOUR CORNERS GENERATING STATION.

Section 19 of the 1960 Lease, Section 24 of the 1966 Lease and Section 25 of the 1966 Lease (as amended by Section 12 of the 1985 Lease Supplement) are deleted in their entirety and replaced as follows:

7.1 Without limiting the scope or effectiveness of the provisions of Section 17 of the 1960 Lease (Operation of Power Plant) or Section 22 of the 1966 Lease (Operation of Enlarged Four Corners Generating Station), APS and the Lessees shall comply with the terms of the Four Corners Generating Station Preference Plan (the “Plan”), attached as Exhibit C.

7.2 In the event that, in the opinion of their counsel, federal law develops in the future, to permit APS and the Lessees, respectively, to grant a preference in employment based on tribal affiliation, as distinguished from a “Native American Indian” preference in employment, APS and the Lessees shall practice a Navajo preference in employment at the Plant in accordance with the requirements of this Section 7 and the Plan.

7.3 If, at any time, APS’s then current Collective Bargaining Agreement (which governs labor at the Plant), as negotiated by APS, in its sole discretion, conflicts with this Section 7 or the Plan, then APS’s Collective Bargaining Agreement shall take precedence.

10

8 ADVISORY COMMITTEE.

APS, the Lessees, and the Nation shall establish a Four Corners Advisory Committee for the purpose of promoting open dialogue between them regarding operations of the Plant.

8.1 The Committee shall consist of two members of the Navajo Nation Government with experience in energy-related matters, one from the executive and one from the legislative branch, and two senior officials representing APS and the Lessees, who shall be tasked to work together and in consultation with their respective leaderships to resolve concerns raised by APS and the Lessees or the Nation in a mutually beneficial manner. The Committee shall meet regularly, but no less than two times a year. Discussion topics and updates may include voluntary compliance agreements, the impact of plant operations on the Nation’s members and surrounding communities and emerging issues.

8.2 APS and the Lessees or the Nation may submit disagreements and disputes to the Committee for discussion and possible resolution. Decisions of the Committee shall be in the nature of recommendations and shall not be binding on APS and the Lessees or the Nation.

9 ANNUAL PAYMENT.

9.1 The Annual Payment shall replace all compensation for rents, rights of way, or otherwise, set forth in the § 323 Grants (as to the § 323 Grant Land), the 1960 Lease and the 1966 Lease, as applicable. All sections of the aforementioned documents imposing a payment obligation on APS and the Lessees are hereby deleted.

9.2 The Annual Payment shall be $7,000,000, as adjusted from the April 2011 CPI (defined below), and shall begin on the Amendment Effective Date. All subsequent Annual Payments shall be subject to annual adjustments, based upon changes in the April Consumer Price Index U.S. City Average for All Urban Consumers, published by the U.S. Bureau of Labor Statistics (“CPI”). The annual CPI adjustment for the Annual Payment shall be as set forth in Exhibit D.

11

9.3 On or before July 6 of each year, APS and the Lessees shall submit one check for the Annual Payment to the Nation and indicate the adjustment required by the CPI.

9.4 No Lessee shall be responsible or liable to the Nation for the payment of any portion of such Annual Payment of any other Lessee. In the event that one or more Lessees fails to pay the Nation its portion of such Annual Payment at the time such Annual Payment is submitted to the Nation, APS (or the then operator of the Plant) shall inform the Nation of the name of the Lessee(s) failing to make the Annual Payment and the specific amount of each such Lessee’s shortfall. In the event the Nation incurs costs associated with obtaining the required Annual Payment owed, the Nation shall be entitled to recover from the defaulting Lessee(s) its associated costs, including, but not limited to, attorney’s fees, filing fees and interest accrued. A list of each Lessee’s portion of the Annual Payment shall be provided to the Nation.

9.5 The Nation agrees that the Annual Payment payable by APS and the Lessees constitutes fair and adequate consideration for the rights granted in the 1960 Lease, the 1966 Lease, the Existing § 323 Grants and the Renewed § 323 Grants.

9.6 Upon agreement between the Lessees, the percentage of the Annual Payment owed by each of APS and the Lessees, respectively, may be changed without the consent of the Nation. But in no event shall the amount due be less than 100% of the Annual Payment, as calculated in accordance with Section 9.2. In the event of a change in payment percentages, an updated list of each Lessee’s portion of the Annual Payment shall be provided to the Nation. In consideration of the Annual Payment made by APS and the Lessees, respectively, the Nation releases APS and the Lessees from all and any kind of claims, suits, actions, causes of action, rights, liabilities, and obligations (the aforementioned, collectively referred to as “Claims”), whether past, present, or future, known or unknown, for or related to compensation due under the 1960 Lease or 1966 Lease, or compensation for the Existing § 323 Grants and the Renewed § 323 Grants.

12

9.7 In consideration of the Annual Payment made by APS and the Lessees, respectively, the Nation releases APS and the Lessees from and settles all outstanding issues and potential Claims, under the 1960 Lease or 1966 Lease, or under the Existing § 323 Grants. Notwithstanding the foregoing, the release set forth in this Section 9.7 shall not apply to any claims arising under Section 10 of this Amendment.

9.8 APS and the Lessees release the Nation from and settle all outstanding issues and potential Claims under the 1960 Lease or the 1966 Lease, or under the Existing § 323 Grants. Notwithstanding the foregoing, the release set forth in this Section 9.8 shall not apply to any claims arising under Section 10 of this Amendment.

10 APS’S 230kV LINES.

APS and the Nation disagree as to whether the provisions of Section 17 of the 1960 Lease (Operation of Power Plant) or Section 22 of the 1966 Lease (Operation of Enlarged Four Corners Generating Station) apply to the Existing §323 Grants listed on Exhibit B for the 230kV lines identified as (a) Flagstaff to Leupp and (b) Cholla to Leupp (collectively, the “Leupp Lines”). APS and the Nation each reserve the right to assert that the aforementioned sections apply or do not apply to the Leupp Lines, as the case may be.

11 DECOMMISSIONING.

Upon the decommissioning of the Initial Four Corners Plant, the Four Corners Project or any part of either facility, the final decommissioning obligations of APS as to the Initial Four Corners Plant and of the Lessees as to the Four Corners Project shall be limited to the requirements under the applicable federal environmental laws existing at the time of such decommissioning. All or any part of any such decommissioning may occur at any time during the term of either the 1960 Lease or the 1966 Lease, as applicable.

13

12 MOENKOPI SUBSTATION.

In the event that there is a future expansion of the Moenkopi Substation, it shall be subject to an increase in APS’s portion of the Annual Payment by $1500 per acre (in April 2009 dollars) for up to 100 acres. The $1500 per acre payment shall be adjusted annually by the CPI (in April 2009 dollars). The expansion shall be subject to all applicable regulatory requirements.

13 ASSIGNMENTS.

The second paragraph of Section 19 of the 1966 Lease is deleted and replaced as follows: Except as set forth in the first paragraph of Section 19 of the 1966 Lease and in Section 9.6 of this Amendment, and except for any assignment, sublease or other transfer by a Lessee to its Affiliate, all other assignments, subleases, or other transfers of rights (including operating rights) of APS related to the 1960 Lease or the Lessees related to the 1966 Lease shall be subject to the prior written consent of the Nation, which consent shall not be unreasonably withheld, nor conditioned on any payments or changes to the terms and conditions of the respective leases, other than nominal administration fees.

14 SETTLEMENT AND CLOSING AGREEMENTS.

Each Party shall execute a new Settlement and Closing Agreement in form and substance substantially similar to the proposed sample Settlement and Closing Agreement attached as Exhibit F. Once executed, the Settlement and Closing Agreement will be effective as of July 6, 2016.

14

15 NO CROSS DEFAULT.

Notwithstanding anything to the contrary in this Amendment, the 1960 Lease or the 1966 Lease, a default by APS under the 1960 Lease, as amended by this Amendment, shall not constitute a default by Lessees under the 1966 Lease, and a default by Lessees under the 1966 Lease, as amended by this Amendment, shall not constitute a default by APS under the 1960 Lease.

16 PRIMARY FUEL.

The primary fuel used at the Plant shall be coal.

17 THIRD PARTY BENEFICIARIES.

The 1960 Lease and the 1966 Lease are not intended to confer upon any third person any rights, privileges, waivers, obligations, or remedies granted hereunder. If, on or before July 6, 2018, SCE has sold its share of the Four Corners Project (“SCE’s Share”), the Nation agrees that, without any additional consent or compensation, such buyer(s) of SCE’s Share (“Buyers”) shall (a) automatically, upon the closing of such a sale, become a Lessee(s) under the 1966 Lease and (2) assume the portion of the Annual Payment attributable to SCE’s Share. Upon the closing of such transaction, all such Buyers shall be express third party beneficiaries under this Section 17, and such Buyers and the Nation shall have first party rights to enforce full performance of this Section 17 against each other.

18 EXECUTION IN COUNTERPARTS.

This Amendment may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument and as if all of the Parties to the aggregate counterparts had signed the same instrument. Any signature page of this Amendment may be detached from any counterpart thereof without impairing the legal effect of any signatures thereon, and may be attached to other counterparts of this Amendment identical in form hereto but having attached to it one or more additional signature pages.

15

This Amendment has been executed by the duly authorized representatives of the Parties, effective as of the Amendment Effective Date.

THE NAVAJO NATION
By:	/s/ Ben Shelly
	Printed Name: Ben Shelly
	Its: President

State of Arizona

County of Apache

The foregoing instrument was acknowledge before me this 7th day of March, 2011  by	Ben Shelly the President of
	(Name)              (Title)

THE NAVAJO NATION, on behalf of The Navajo Nation.

/s/ Angela Cody

Notary Public

My Commission Expires:

ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, in its individual capacity and as a Lessee
By:	/s/ Mark A. Schiavnoi
	Printed Name: Mark A. Schiavnoi
	Its: Senior Vice President, Fossil

State of Arizona

County of Maricopa

The foregoing instrument was acknowledge before me this 8th day of November, 2010 by Mark A. Schiavnoi the Senior

(Name)                                         

Vice President, Fossil of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of the corporation.

            (Title)

	/s/ Norann Asciutto
	Notary Public
My Commission Expires: 2-27-14

16

My Commission Expires:	Notary Public
Reviewed and Approved	EL PASO ELECTRIC COMPANY, a
Legal Department	Texas corporation
/s/ [ILLEGIBLE]	By:	/s/ David W. Stevens
		Printed Name: David W. Stevens
		Its: CEO

State of Texas

County of EL PASO

The foregoing instrument was acknowledge before me this 8th day of November, 2010  by	David W. Stevens the CEO of
	(Name)               (Title)

EL PASO ELECTRIC COMPANY, a Texas corporation, on behalf of the corporation.

	/s/ Carolina Pena
	Notary Public
My Commission Expires: 3-24-2011
	PUBLIC SERVICE COMPANY OF NEW MEXICO,
	a New Mexico corporation
	By:	/s/ Patricia K. Collawn
		Printed Name: Patricia K. Collawn
		Its: President & CEO

State of New Mexico

County of Bernalillo

The foregoing instrument was acknowledge before me this 8^th day of November, 2010 by Patricia K. Collawn the President &

(Name)                       (Title)         

CEO of PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation, on behalf of the corporation.

/s/ [ILLEGIBLE]

Notary Public

17

My Commission Expires:

September 12, 2012

TUCSON ELECTRIC POWER COMPANY,
an Arizona Corporation
By:	/s/ Michael J. Deconcini
	Printed Name: Michael J. Deconcini
	Its: Chief Operating Officer

State of Arizona

County of Pima

The foregoing instrument was acknowledge before me this 8^th day of November, 2010 by Michael J. Deconcini the Sr. Vice

(Name)                                       

President & Chief Operating Officer of TUCSON ELECTRIC POWER COMPANY, an Arizona corporation, on behalf of

                    (Title)

the corporation.

	/s/ Janice Spencer
	Notary Public
My Commission Expires: 8/8/11

18

SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT, an agricultural improvement district organized under the laws of the State of Arizona.

		Reviewed by SRP Legal Services
By:	/s/ David Rousseau	By:	/s/ Kanlee Ramaley
	David Rousseau, President or		Signature
	John R. Hoopes, Vice President
			/s/ Kanlee Ramaley
Date:	11/23/2010		Printed Name
		Date:	11/23/2010
Attest and Countersign:
By:	/s/ Terrill A. Lonon
	Terrill A. Lonon, Secretary or
	Stephanie K. Reed, Assistant Secretary
Date:	11/23/2010

State of Arizona

County of Maricopa

The foregoing instrument was acknowledge before me this 23^rd day of November, 2010 by David Rousseau the President of

(Name)                 (Title)               

SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT, an agricultural improvement district organized under the laws of the State of Arizona.

	/s/ Stephanie K. Reed
	Notary Public
My Commission Expires: August 5, 2011

19

EXHIBIT A

See Amendment 2

Exhibit B

Item	Existing § 323 Grants	Property or Facility	APS File #	Grant Date	Expiration Date	Acres
1	Plant Site	Amended Original Lease (Units 1-3)		12/01/60	07/06/16
		New Lease (Units 4-5)		07/06/66	07/06/16
							3,466.42
2	Ancillary Facilities	Utah Mine Haul Road (Communication Lines and Access Road)	IN-13	07/2861	07/28/11		19.25
		Plant — Coal Lease Area — 69 kV	IN-15	12/15/61	12/15/11		3.75
		Pumping Station to Plant Access Road & Pipeline	IN-12	04/02/62	04/02/12		40.91
		River Pumping Station to Plant — 69 kV	IN-11	04/02/62	04/02/12		21.74
		Plant — EPNG Bridge / Access Rd	IN-16	07/03/63	07/03/13		37.57
		Pumping Station to Plant Access Road & Pipeline Addition	IN-92	04/21/69	04/21/19		10.36
							133.58
3	500 kV ROW	El Dorado 500 kV (Navajo portion only)	IN78 INH-79, INH-80	03/22/67	03/22/17		3,959.29
	345 kV ROW	Four Corners to Cholla	IN-17	05/26/61	05/26/11		5,658.91
	230 kV ROW	Flagstaff to Leupp	IN-4	09/12/57	09/12/07		102.82
		Cholla to Leupp	IN-7	09/21/60	09/21/10		249.16
4	Substation Sites	12 kV line and Roadway to Moenkopi Switchyard	INH-88	04/24/70	04/27/95		1.12
		Leupp Substation	IN-5	05/06/59	05/06/09		.43
		Moenkopi Switchyard	INH-83	04/09/68	04/09/18		211.09
5	Communication Sites	Preston Mesa Communication Site	IN-1182	12/30/96	12/30/14		0.23
		Jacks Peak Communication Site	IN-1181	04/16/02	04/15/17		1.75
		Dezza Bluff Communication Site	IN-1357	12/15/97	12/14/17		0.08
		Zilnez Mesa Microwave Site, Navajo Reservation	IN-113	01/03/73	01/03/23		2.40
		Roof Butte Communication Site	IN-85	07/07/70	07/07/20		0.02
		Marsh Pass Communication Site	IN-116	01/03/73	01/03/23		3.90

* Certain of the terms used to describe the listed property or facilities have the meanings given to them in the 1960 Lease and 1966 Lease.

Exhibit C

FOUR CORNERS GENERATING STATION

PREFERENCE PLAN

March 7, 2011

Table of Contents

I. INTRODUCTION	1
II. PREFERENCE POLICY STATEMENT	1
III. SELECTION	1
IV. GOALS	2
V. TRAINING	3
VI. RECRUITMENT/ADVERTISING FOR REGULAR EMPLOYEES	3
VII. ADVERTISING/RECRUITING FOR TEMPORARY EMPLOYEES	4
VIII. CONTRACT LABOR/SERVICES	4
IX. CROSS CULTURAL COMMUNICATIONS PROGRAM	4
X. DISPUTE RESOLUTION FOR EMPLOYEES	4
XI. ENTIRE AGREEMENT; NO THIRD PARTY BENEFICIARIES	5

I. INTRODUCTION

The purpose of this Preference Plan is to clarify and delineate Arizona Public Service Company’s (“APS”) Indian Preference Plan for the Four Corners Generating Station (“Four Corners”) and specifically, the procedures for giving preference in employment to Indians.

II. PREFERENCE POLICY STATEMENT

Employment at Four Corners is based on qualifications without regard to race, color, creed, religion, national origin, sex, or age, except that preference will be given to qualified Indians, provided, however, that to the extent allowed by law (as set forth in Section 7.2 of the Amendment, to which this Preference Plan is attached), APS will give preference to qualified Navajos rather than to Indians. Each member of APS’s management is responsible for implementing this policy in his/her areas and is held accountable for it in the same way each manager is held accountable for other company policies. In particular, the Plant Manager for Four Corners has overall accountability and responsibility for implementation of this Preference Plan.

III. SELECTION

In order to conduct operations at Four Corners in a safe and effective manner, all positions must be filled by persons qualified to perform the work required. APS has procedures to evaluate the qualifications (knowledge, skills and abilities) required for each job position. In general, these job qualifications are documented in “job descriptions” maintained by APS’s Human Resource Department. Employees may also obtain a copy of their job descriptions by contacting their supervisors.

Job requirements consist of standards which identify the skills, education, and experience necessary to perform a particular job. These job requirements are the basis for hiring decisions and are also used to formulate employee training programs for job classifications with few incumbent-Indian employees. Hence, it is important that the job descriptions describe the true requirements of the job. For this reason, APS will review its job descriptions to assure that the job qualifications are relevant to the job requirements.

Qualifications are assessed on the basis of performance reviews, skills evaluations, experience and education, as appropriate for the position under consideration. Supervisors (and previous employers, in the case of external applicants) may be contacted. Skills may be evaluated by written tests, skill demonstrations, or by supervisory interview. Tests will be validated for job relevancy.

APS is committed to Indian preference in employment. Preference will be given to Indians who possess the skills and abilities to fulfill the job requirements established above.

1

IV. GOALS

The purpose of this Preference Plan is to provide a means to increase the employment of Indians at Four Corners, in both regular full-time and temporary positions. In particular, APS intends to focus on increasing the overall employment of Indians at Four Corners and promoting Indians into management positions.

Analysis of Indian employment levels by job classification will lead to establishing goals for job placement and training. These goals will be reviewed annually to evaluate the progress made toward the objective, and revised as necessary.

The commitment of APS is to offer available job opportunities to Indians who satisfy job requirements, whether the person is a current employee or a non-employee identified through recruitment and advertising. Through the adoption and implementation of training programs at Four Corners, the long-range goal is to develop a pool of Indian candidates qualified for all positions.

Openings created through resignation, discharge, transfer, promotion, or a newly created position cause the posting of an internal “bid” and create opportunities for internal movement through the bid process. Bidding is the established process by which job vacancies are announced, advertised and filled. When vacancies occur, employees, who feel they have the qualifications for a particular job, may submit their internal applications (bids) for consideration.

The bid process frequently creates a cascading effect, as employees vacate existing jobs to fill positions that result from another employee accepting a bid to fill the original vacancy. When an Indian bidder accepts a position vacated by another Indian, the net effect on the overall percentage of Indian employment is zero. While Indian bidders will be given preference in accordance with this Preference Plan, an increase in the total percentage of Indian employees at Four Corners can be expected only when the cascading effect of the bid system results in the employment of external Indian candidates.

Nevertheless, the potential for increasing the number of Indian employees is greater in certain job classifications than in others. Some of these job classifications are:

• First and second level supervision

• Operations (Operator Trainee through Control Operator)

• Machinist

• Plant Mechanic

• Electrician

• Equipment Operator

• Plant Chemist

• Scheduler

2

Four Corners management will give these job classifications particular attention to increase employment of Indians. Additionally, technical and professional recruiting will be increased to locate, identify, and employ suitable Indian candidates for engineers, technicians, and professional positions.

V. TRAINING

When there are too few qualified Indian bidders, internal training programs to increase the availability of Indian bidders may be appropriate. Training programs should focus on raising the level of skills, knowledge and abilities of Indians in “feeder jobs.” These are jobs which typically provide employees for higher level jobs, particularly when the lower level job has skill, knowledge and ability requirements that are prerequisites for a higher level job. Training should continue until the goal has been met. Other “in-place” training programs, such as apprenticeships and operations training, are on-going and continue to provide trained replacements for journeymen.

Indians will be encouraged to enhance their careers at APS by taking advantage of on-the-job training, apprenticeships, and in-house and off-the-job educational courses. As a specific part of this Preference Plan, the following actions will be taken to provide opportunities for Indians to advance to journeyman-level and supervisory positions.

1. New apprenticeships will be awarded only to qualified Indians.

2. Currently employed Indian journeymen will be selected for supervisory training to make them better qualified for future opportunities in foreman positions.

Because of the magnitude of the work and its accompanying time constraints, virtually everyone at Four Corners is affected by an overhaul. Four Corners has chosen to supplement the knowledge, skills and experience of its regular full-time employees with those of temporary workers with job specific skills. During an overhaul, where possible, regular full time employees are upgraded to higher level skill positions including supervisory positions. In this manner, employees may further expand the practical application of their technical and supervisory skills.

VI. RECRUITMENT/ADVERTISING FOR REGULAR EMPLOYEES

Recruitment is any activity that causes individuals to apply for employment. Advertising is one method of recruitment. Examples of other methods include meetings with graduating college seniors, participation in trade fairs, and day programs.

Since most regular full-time jobs at Four Corners are filled internally, a large recruitment effort is not needed. Thus, recruitment of regular full-time employees should be limited to those positions which are not filled by Indians internally. For purposes of this Preference Plan, recruitment will concentrate on jobs in which Indians are underutilized.

3

In an effort to attract qualified Indian applicants, contacts with key organizations throughout the Navajo Reservation will be maintained, although contacts within the Western Navajo Agency will be emphasized. In addition, Four Corners will work with appropriate tribal agencies to develop other potential recruitment sources.

Universities, vocational schools, Joint Training and Partnership Act classroom training programs, the Navajo Division of Education, the ONLR, and employment service offices located in the vicinity of Four Corners will be included in the recruitment and advertising efforts of Four Corners. Technical and professional jobs will be emphasized in recruitment efforts at colleges, universities, and in periodic advertisements to attempt to locate and identify suitable Indian candidates for employment opportunities.

Advertising and recruiting efforts will include a statement that APS at Four Corners recognizes Indian preference in employment. The following statement will be included in all advertisements for employment opportunities at Four Corners and on bid sheets posting jobs at Four Corners:

APS follows a policy of giving preferential treatment to Indians in connection with employment at the Four Corners Generating Station.

VII. ADVERTISING/RECRUITING FOR TEMPORARY EMPLOYEES

Each year, temporary employees are hired for certain specific assignments at Four Corners. Only when no qualified Indian applicant is found, after a thorough review of returning Indian applicants, existing files on temporary Indian employees, and new applications from Indians (generated by advertising), will a temporary position be filled by a non-Indian.

VIII. CONTRACT LABOR/SERVICES

APS will select qualified Indian-owned businesses, when available, to provide contract labor or services at Four Corners. APS will notify its vendors (a) of the employment and contracting preference policy at Four Corners; and (b) that they are expected to comply with applicable laws and regulations.

IX. CROSS CULTURAL COMMUNICATIONS PROGRAM

APS will develop and implement a cross-cultural program designed to provide a forum for Indian and non-Indian employees to openly examine and discuss the culturally significant customs, beliefs, values, and social mores that all individuals bring with them to the workplace.

X. DISPUTE RESOLUTION FOR EMPLOYEES

APS acknowledges the value of maintaining a work environment free of prejudice and discrimination. Nevertheless, despite even the best of intentions, complaints do arise, and the parties have determined that complaints of whatever nature are best handled internally, without the involvement of external agencies. Therefore, employees are encouraged to take advantage of APS’s existing internal processes. Through this approach, a wide variety of employment related complaints may be addressed and resolved.

4

If Navajo Nation officials become aware of an employment concern at Four Corners, the Navajo Nation must bring the issue to the Advisory Committee, formed pursuant to the Lease (to which this Preference Plan is attached), for resolution.

XI. ENTIRE AGREEMENT; NO THIRD PARTY BENEFICIARIES

This Preference Plan is the entire agreement between the Parties concerning its subject matter and supersedes all prior agreements and understandings, whether or not written, including without limitation the letter agreement dated March 8, 1985 between APS and the Navajo Nation and signed by G. Mark De Michele and Peterson Zah. This Preference Plan also is not intended to confer upon any person other than the Parties any rights, privileges, waivers, obligations or remedies granted hereunder.

5

Exhibit D

Annual Payment for 2016 and all subsequent years:

7,000,000.00 x	CPI for April in year which Annual Payment is due
	CPI for April 2011

Exhibit E

This exhibit intentionally not used.

Exhibit F

(Includes Exhibits A-D of the Restated and Amended Settlement and Closing Agreement)

DRAFT

11/4/2010 3:30 PM

Restated and Amended Settlement and Closing Agreement

This Restated and Amended Settlement and Closing Agreement (the “Restated Agreement”) amends the Settlement and Closing Agreement dated August 15, 2002 (“Original Agreement”) and is entered into as of the Effective Date (as defined in Section 18) by Arizona Public Service Company (“APS”) and the Office of the Navajo Tax Commission (“ONTC”), acting on its own behalf and, pursuant to Section 103 of the Navajo Nation Uniform Tax Administration Statute (“UTAS”), on behalf of the Navajo Nation. APS and the ONTC may be referred to herein individually as a “Party” or collectively as the “Parties.”

Recitals

A. Pursuant to Section 105 of UTAS, the ONTC, on behalf of the Navajo Nation, issued an assessment to APS on [Date] seeking to assess the Possessory Interest Tax (“PIT”) on APS in connection with its ownership and operation of the Four Corners Power Plant (the “Plant”), switchyards, and transmission and distribution facilities within the Navajo Nation (hereinafter, the Plant, switchyards, and transmission and distribution facilities within the Navajo Nation are collectively referred to as the “Facilities”). Pursuant to Regulation 1.125 of the ONTC Tax Administration Regulations, the ONTC also issued on [Date] a private ruling asserting that it has jurisdictional authority to impose the Business Activity Tax (“BAT”) upon APS’ activities related to the Facilities. Pursuant to Section 133 of UTAS, the ONTC is entering into this Restated Agreement.

B. APS and the other participants in the Plant (collectively, the “Participants”) assert that neither the Navajo Nation nor the ONTC has jurisdictional authority to impose any tax on APS, the Participants or the Facilities based on (i) certain agreements between the Navajo Nation, APS and Participants, including without limitation, certain covenants in leases entered into by APS, the Participants and the Navajo Nation and approved by the United States (“Leases”) and in federal grants of rights-of-way issued to APS and the Participants by the United States (“Grants”), (ii) the location of the Facilities on federally granted rights-of-way, (iii) the non-Indian character of APS and the Participants, and (iv) relevant case law.

1

C. The ONTC asserts that it possesses jurisdictional authority to administer taxes enacted by the Navajo Nation with respect to the Participants, including APS, and the Facilities based on (i) certain agreements between the Navajo Nation, APS and the Participants, including without limitation, certain covenants in the Leases and Grants, (ii) the location of the Facilities on lands held in trust by the United States for the benefit of the Navajo Tribe, and (iii) relevant case law.

D. The Parties entered into the Original Agreement for purposes of settling the dispute and to avoid litigation over the question of the jurisdictional authority of the Navajo Nation and ONTC to tax the Facilities and APS, based on its ownership interest in and operation of the Facilities.

E. The Parties desire to restate, amend and extend the Original Agreement and are thus entering into this Restated Agreement in accordance with the express terms set forth below.

WHEREFORE, THE PARTIES AGREE AS FOLLOWS:

1. Settlement Payments. Subject to the terms and conditions contained in this Restated Agreement, APS will make settlement payments as specified below (“Settlement Payments”):

a. PIT Settlement Payments.

(i) Beginning with calendar year 2001 and continuing through July 7, 2041 (the “Amended Term”), APS will pay to ONTC the following amount as a PIT Settlement Payment for the APS-owned Facilities, subject to adjustment as provided in subsection a(ii) of this Section 1:

Calendar Year	PIT Settlement Payment
2001	$2,993,515.00
2002 – 2003	$5,987,030.00 per year
2004 – 2040	$6,342,600 per year
2041	$3,171,300.00

2

(ii) Beginning July 8, 2016 and continuing through July 7, 2041, the PIT Settlement Payment is subject to reduction in the event APS and/or the Participants permanently shut down any of the Facilities and/or unit(s) of the Plant in which APS has an ownership interest, including but not limited to the permanent shut down of the entire Plant (the “Permanently Shut Down Facilities”). For any Permanently Shut Down Facilities salvage value will be determinative of value, and salvage value will be based on 5% of original or acquisition cost of the Permanently Shut Down Facilities in question. In the event of any permanent shut down under this Section 1a(ii), the PIT Settlement Payment will be recalculated in two steps:

a. Step One: PIT Settlement Payment will be proportionally reduced by multiplying the PIT Settlement Payment by a factor that represents the ratio of the original or acquisition cost of the APS-owned Facilities within the Navajo Nation that are not Permanently Shut Down Facilities divided by the total original or acquisition cost of the APS-owned Facilities.

b. Step Two: The proportionately reduced PIT Settlement Payment derived under Step One will then be increased by adding the product of a 3% in-lieu-of tax rate and the salvage value (i.e., 5% of original or acquisition cost) of the Permanently Shut Down Facilities. A sample calculation in included as Exhibit D to this Restated Agreement.

(iii) In the event APS constructs a new unit or units at the Plant during the Amended Term, the PIT Settlement Payment will be proportionally increased by an amount that represents the product obtained by multiplying the original or acquisition cost of the new APS-owned unit or units by the following factor:

a. The PIT Settlement Payment of $6,342,600 divided by the original or acquisition cost of the APS- owned Facilities within the Navajo Nation as of the Effective Date of this Restated Agreement. A sample calculation in included as Exhibit 1 to this Restated Agreement

(iv) APS will pay the PIT Settlement Payment specified above (as may be adjusted pursuant to Section 1a(ii) or Section 1a(iii), above) for calendar years 2002-2040 on a semi-annual basis, with the first half for each calendar year due November 1 and the second half due May 1 of the following year. APS will pay the PIT Settlement Payment specified above for calendar year 2041 on or before November 1, 2041. On or before June 1 of each calendar year during the term of this Restated Agreement, APS will provide to the ONTC, for informational purposes only, the form attached as Exhibit A.

3

(v) Interest on any late payment of the PIT Settlement Payment will be computed from the date the PIT Settlement Payment was first due to the date such payment is received by the ONTC. The rate of interest on any late payment will be equal to the rate then being used by the Internal Revenue Service for an underpayment of taxes by an individual. If APS fails to timely pay the PIT Settlement Payment, APS also will pay an additional amount equal to 5% of its PIT Settlement Payment. For each full month the payment is overdue, APS will pay an additional amount equal to 0.5% of its PIT Settlement Payment; provided, however, that the maximum additional amount APS must pay for the failure to timely pay shall not exceed 10% of the PIT Settlement Payment amount due. If APS fails to timely provide the Report for PIT Settlement Payment, attached as Exhibit A, as required by Section 1(a)(iv) of this Restated Agreement, APS will pay an additional 5% of its PIT Settlement Payment due for the period for each month or fraction thereof that the Report for PIT Settlement Payment is not provided; provided, however, that the minimum additional amount to be paid for failure to timely provide such Report for PIT Settlement Payment shall be $50 and the maximum additional amount shall not exceed 25% of APS’ PIT Settlement Payment for that period. For good cause shown, the ONTC may in its discretion relieve APS from all or part of the requirements imposed under this Section 1.a(v).

(vi) APS will provide, within six (6) months of the Effective Date of this Restated Agreement, a schedule of original or acquisition cost for the Facilities in which APS has an ownership interest (including the Permanently Shut Down Facilities) for use in connection with the calculations provided for in Section 1.a(ii). In addition, if APS constructs a new unit or units at the Plant for purposes of Section 1.a(iii), APS will provide a schedule of original or acquisition cost for such new unit or units within six (6) months after its/their completion, for use in connection with the calculations provided for in Section 1.a(iii).

(vii) The ONTC expressly agrees that APS is hereby released from any obligation and will not be required or requested to make any other payment with respect to any other amounts that the ONTC asserted or could have asserted were payable prior to execution of this Restated Agreement.

b. BAT Settlement Payment.

(i) Effective as of July 6, 2001 and continuing through the Amended Term, APS will calculate its BAT Settlement Payment amount using the following formula:

BAT Settlement Payment =

[ (R * AI * Net KWhrs) less (Deductions) less (10% Standard Deduction) ] * 5%

4

Where R = $.0256 / KWhr.

Where Net KWhrs = APS’ share of actual net kilowatt hours generated from the Plant during the quarterly period.

Where Deductions = (1) Salaries and/or other compensation paid to members of the Navajo Nation; (2) Purchases of Navajo goods and services; and (3) Any payment made to the government of the Navajo Nation, except for the BAT Settlement Payment paid pursuant to this Restated Agreement and any penalties or fines.

Where Standard Deduction = an amount equal to the greater of ten percent of (R * AI * Net KWhrs) or $125,000.00.

As set forth on Exhibit C, APS will include in its Operating Report provided to the ONTC a statement of actual net generation for each quarter.

Where AI = an adjustment calculated in the 3^rd Quarter of each year based upon a 5-year rolling average of Producer Price Index data published by the Bureau of Labor Statistics. Annual adjustments shall be cumulative, i.e., the total current year adjustment shall be equal to the incremental current year adjustment multiplied by the previous year’s adjustment. The incremental adjustment shall be calculated utilizing the following methodology:

AI = (75% * Cost Index) plus (25% * Revenue Index).

Where Cost Index =

42.3%	* Bituminous Coal and Lignite: West (BLS Series PCU1211#214)
plus	0.9% * Natural Gas (BLS Series PCU1331#A2)
plus	7.6% * Other Heavy Construction (BLS Series PCUBHVY#)
plus	49.2% * Unit Labor Costs: Non-Farm Business (BLS Series PRS85006112)

Where Revenue Index =

65.2%	* Electric Power and Natural Gas Utilities, Other, Mountain (BLS Series PCU4981#148)
plus	34.8% * Electric Power and Natural Gas Utilities, Other, Pacific (BLS Series PCU4981#149)

5

If any of the BLS indices used in this calculation are discontinued, the Parties shall mutually agree upon an equivalent substitute BLS index. The Parties agree that, beginning January 1, 2002, the Bituminous Coal and Lignite: Surface Mining (BLS Series PCU1211#1) will be substituted into the calculation in place of Bituminous Coal and Lignite: West (BLS Series PCU1211#214).

A calculation of AI for the 3^rd Quarter 2001 through the 2^nd Quarter 2002 BAT Settlement Payments is attached as Exhibit B. The 5-year average of index data for 1996 through 2000 is used to develop this initial adjustment.

Each subsequent annual adjustment will be made for the 3^rd Quarter BAT Settlement Payment using the 5-year rolling average of index data through the end of the previous year.

A sample calculation of AI for the 3^rd Quarter 2002 through 2^nd Quarter 2003 BAT Settlement Payments using estimated data is included in Exhibit B. Calculations in subsequent years will follow this same formula.

(ii) APS will make its BAT Settlement Payments on a quarterly basis, with payments due 45 days after the end of each calendar quarter. APS will, at the time of making such payments, provide to the ONTC an Operating Report containing the following information used to calculate APS’ BAT Settlement Payment:

(a) APS revenue requirement, as adjusted by AI;

(b) Net KWhrs for the quarter;

(c) Deductions as defined above; and

(d) Standard Deduction.

The format for the Operating Report is set forth in Exhibit C.

(iii) Interest on any late payment of a BAT Settlement Payment will be computed from the date the BAT Settlement Payment was first due to the date such payment is received by the ONTC. The rate of interest on any late payments will be equal to the rate then being used by the Internal Revenue Service for an underpayment of taxes by an individual. If APS fails to timely pay the BAT Settlement Payment, APS will pay an additional amount equal to 5% of the BAT Settlement Payment due. For each full month the payment is overdue, APS will pay an additional amount equal to 0.5% of the amount of its BAT Settlement Payment; provided, however, that the maximum additional amount that APS will be required to pay for the failure to timely pay shall not exceed 10% of the BAT Settlement Payment amount due. If APS fails to timely provide to the ONTC an Operating Report required by this Restated Agreement, APS will pay an additional 5% of its BAT Settlement Payment for each month or fraction thereof that the Operating Report has not been provided to the ONTC; provided, however, that the minimum additional amount to be paid for APS’ failure to timely provide such Operating Report will be $50 and the maximum additional amount will not exceed twenty-five percent (25%) of APS’ BAT Settlement Payment for that period. For good cause shown, the ONTC may in its discretion relieve APS from all or part of the requirements imposed under this Section 2.b(iii).

6

(iv) The ONTC expressly agrees that APS is hereby released from any obligation and will not be required or requested to make any other payment with respect to any other amounts that the ONTC asserted or could have asserted were payable prior to execution of this Restated Agreement.

2. Releases.

a. APS hereby releases and forever discharges the ONTC, its predecessors, successors, affiliates, and assigns, of and from any and all claims, demands, damages, actions, causes of action, or suits of whatsoever kind and nature, existing as of the Effective Date of this Restated Agreement, whether now known or unknown to the Parties, or whether asserted or unasserted, related, either directly or indirectly, to any and all PIT and BAT tax assessments and taxes, and interest and penalties thereon, allegedly owed by the ONTC, its predecessors, successors, affiliates, and assigns, to APS arising from APS’ ownership interests or operation of the Facilities.

b. The ONTC hereby releases and forever discharges APS, its predecessors, successors, affiliates, and assigns, of and from any and all claims, demands, damages, actions, causes of action, or suits of whatsoever kind and nature, existing as of the Effective Date of this Restated Agreement, whether now known or unknown to the Parties, or whether asserted or unasserted, related, either directly or indirectly, to any and all PIT and BAT tax assessments and taxes, and interest and penalties thereon, allegedly owed by APS, its predecessors, successors, affiliates, and assigns, to the ONTC or Navajo Nation arising from APS’ ownership interests or operation of the Facilities.

c. The ONTC expressly covenants that it will not seek to apply or assess the Navajo Sales Tax, approved by the Navajo Nation Council pursuant to Resolution No. CO-84-01 on October 18, 2001 (as amended), with respect to any electricity generated at, from or by the Plant except for retail sales of electricity to persons who purchase electricity for that person’s own use, including use in that person’s trade or business and not for resale, redistribution or retransmission, within the Navajo Nation.

7

3. Case Closure.

The Parties agree that the following cases shall be closed:

Possessory Interest Tax: Case No. 01-042

Business Activity Tax: Case No. 01-056

4. Preservation of Rights.

It is understood and agreed that this is a settlement of disputed claims, whether asserted or unasserted, and that nothing contained herein shall be construed as an admission of liability, guilt, or wrongdoing by or on behalf of any of the undersigned Parties, all such liability, guilt, or wrongdoing being expressly denied. The Parties acknowledge and agree that this Restated Agreement shall not prejudice or limit in any way the rights or contentions of any Party. The Parties further agree that this Restated Agreement shall not in any way be deemed a waiver or amendment of any provisions of any other agreement between the Navajo Nation, APS and/or any of the Participants, including but not limited to the Leases and Grants. This Restated Agreement, and the actions of the Parties contemplated hereunder, are not intended, nor shall they be deemed, to constitute any waiver, consent or admission with respect to the existence or lack of regulatory, taxing, or adjudicatory authority or jurisdiction of the Navajo Nation or the ONTC over the Facilities or any Party hereto.

5. Enforcement and Judicial Review.

a. Neither Party shall commence any judicial or administrative action challenging the validity of this Restated Agreement or any Party’s authority to enter into it. Any commencement of such an action by a Party shall constitute a material breach of this Restated Agreement by that Party.

b. Challenge to Validity of the Restated Agreement.

(i) If the ONTC, or any of its representatives, officers, employees, departments or agents (a) commences any judicial or administrative action challenging this Agreement or the ONTC’s authority to enter into it, or (b) otherwise in any manner invalidates or breaches this Restated Agreement or takes any action contrary to this Restated Agreement, APS may, in its sole discretion, elect to seek specific performance of or terminate this Restated Agreement. If the ONTC, or any of its representatives, officers, employees, departments or agents, repeals the PIT or BAT and enacts a replacement tax that the ONTC seeks to assert against APS or the Facilities, APS may terminate this Restated Agreement. The ONTC agrees and recognizes that if APS terminates this Restated Agreement, APS shall have no further obligation or liability to make any Settlement Payments from the date of termination forward. The ONTC further agrees and recognizes that in such circumstance, APS has preserved its rights to contest the jurisdiction of the ONTC or the Navajo Nation to assert or assess any taxes against APS with respect to the Facilities, APS’ activities at the Facilities, or with respect to any other properties or activities within the Navajo Nation.

8

(ii) If APS, or any of its representatives, officers, employees, departments, or agents (a) commences any judicial or administrative action challenging this Restated Agreement or APS’ authority to enter into it, or (b) otherwise in any manner invalidates or breaches this Restated Agreement or takes any action contrary to this Restated Agreement, the ONTC may, in its sole discretion, elect to seek specific performance of or terminate this Restated Agreement. APS agrees and recognizes that, if the ONTC elects to terminate this Restated Agreement, the ONTC has preserved its rights to assert jurisdiction to assess taxes against APS from and after the date of termination with respect to the Facilities, APS’ activities at the Facilities, or with respect to any other properties or activities of APS within the Navajo Nation. If the ONTC elects to terminate this Restated Agreement, the ONTC shall be under no further obligation to accept Settlement Payments in satisfaction of APS’ obligations.

(iii) If any person or entity not a Party to this Restated Agreement or the Navajo Nation, or any of their representatives, officers, employees, agencies, departments or agents, commences any judicial, administrative or other action challenging in any way the Restated Agreement’s validity, the Parties shall jointly request that the court, tribunal, agency, or official before which the action is pending dismiss the action. If the action is not dismissed, either Party may file an appropriate responsive pleading, or otherwise act as reasonably necessary to respond to the action or to otherwise protect such Party. If any person, including the Navajo Nation or ONTC, brings an action or proceeding to assert or challenge the jurisdictional authority of the Nation or ONTC to tax the Facilities or activities at the Facilities with respect to such other person other than APS, each Party agrees not to rely on any ruling in such action or proceeding for purposes of challenging the validity of this Restated Agreement as long as the other Party is not in material breach hereof.

(iv) If any court, tribunal, agency or official determines that this Restated Agreement is non-binding on the ONTC or the Navajo Nation, APS may elect to terminate this Restated Agreement, and if so terminated, APS shall have no further obligation or liability to make any Settlement Payments from the date of termination forward. The ONTC agrees and recognizes that in such circumstance APS has preserved its rights to contest the jurisdiction of the Navajo Nation and ONTC to assert or assess any taxes against APS with respect to the Facilities, APS’ activities at the Facilities, or with respect to any other properties or activities within the Navajo Nation.

9

(v) If any court, tribunal, agency or official determines that this Restated Agreement is non-binding on APS, the ONTC may elect to terminate this Restated Agreement, and if so terminated, APS agrees and recognizes that in such circumstance, the ONTC has preserved its rights to assert jurisdiction to assess any taxes against APS with respect to the Facilities, APS’ activities at the Facilities, or with respect to any other properties or activities within the Navajo Nation.

c. Other Taxes. Nothing in this Restated Agreement affects the rights, if any, of (i) the Navajo Nation or ONTC to seek to enforce taxes other than the Sales Tax (except as otherwise provided in Section 2(c) above), PIT or BAT on APS or the Facilities or (ii) APS to challenge any such action by the Navajo Nation or ONTC, including when permitted by federal law, bringing such an action in federal court.

d. Enforcement of the Restated Agreement. Enforcement of this Restated Agreement by either Party shall be pursuant to this Restated Agreement and not pursuant to any Navajo Nation or other law independent of this Restated Agreement. Nothing in this Restated Agreement shall or may be deemed to limit a Party’s right to seek enforcement of this Restated Agreement or defend any claim in federal or tribal court where otherwise permitted by law. Nothing in this Restated Agreement shall or may be deemed as a consent to federal or tribal court jurisdiction by either Party.

6. Assignment.

APS may transfer or assign, without the consent of the Navajo Nation or ONTC, all or any portion of its interests and obligations under this Restated Agreement to any parent, subsidiary, affiliate or successor in interest of APS by merger, acquisition, or consolidation or to any other current or future owner of the Facilities, provided that the assignee assumes in writing all of APS’ obligations under this Restated Agreement.

7. Representations.

Each Party represents and warrants as of the Effective Date of this Restated Agreement as follows:

a. It has full legal right, power and authority to execute, deliver and perform this Restated Agreement;

b. It has taken all appropriate and necessary action to authorize the execution, delivery and performance of this Restated Agreement;

10

c. It has obtained all consents, approvals and authorizations necessary for the valid execution and delivery of this Restated Agreement;

d. This Restated Agreement constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms, except as such enforceability may be limited by applicable bankruptcy or insolvency laws or by limitation upon the availability of equitable remedies;

e. It is not in violation of any applicable law promulgated or judgment entered by any federal, state, local or other governmental body, which violations, individually or in the aggregate, would adversely affect the performance of its obligations under this Restated Agreement; and

f. The execution, delivery and performance by it of this Restated Agreement, the compliance with the terms and provisions hereof and the carrying out of the transactions contemplated hereby, (i) do not conflict with and will not conflict with or result in a breach or violation of any of the terms and provisions of its organizational documents, and (ii) to the best of its knowledge, do not conflict with and will not conflict with or result in a breach or violation of any of the terms and provisions of any law, rule or regulation, or any order, writ, injunction, judgment or decree by any court or other governmental body against it or by which it or any of its properties is bound, or any loan agreement, indenture, mortgage, note, resolution, bond or contract or other agreement or instrument to which it is a party or by which it or any of its properties is bound, or constitute or will constitute a default thereunder or will result in the imposition of any lien upon any of its properties.

8. Successors and Assigns.

This Restated Agreement shall be binding on and inure to the benefit of the Parties hereto and their successors and assigns.

9. Entire Agreement.

Except for any separate agreement of the Parties settling disputed claims related to applicability of the BAT to certain transmission and distribution facilities within the Navajo Nation, this Restated Agreement reflects the entire agreement of the Parties relating to taxation of the Facilities and no other agreement written or oral shall be used to effect any changes of the provisions retained herein. No amendment of this Restated Agreement shall be valid unless in writing and signed by all Parties.

11

10. Counterparts.

This Restated Agreement may be signed in counterparts, each of which shall be deemed an original. Facsimile signatures shall be as valid as original signatures until each Party receives a fully signed counterpart with original signatures. Each Party shall provide the other Party with original signatures so that each Party shall have a fully signed counterpart within five business days after the date of the last signature.

12

11. Relationship of Parties.

Nothing herein may be construed to create an association, joint venture, trust, or partnership, or to impose a trust or partnership covenant, obligation or liability on or with regard to any one or more of the Parties.

12. Severability.

Subject to the provisions of and except as otherwise provided in Section 5, Enforcement and Judicial Review, of this Restated Agreement, if any term or condition of this Restated Agreement is held to be invalid, void, or unenforceable by any court or tribunal of competent jurisdiction, that holding shall not affect the validity or enforceability of any other term or condition of this Restated Agreement, unless either Party determines in its sole discretion that enforcing the balance of the Restated Agreement would deprive that Party of a fundamental benefit of its bargain.

13. Adjustment of PIT and BAT Settlement Payment Amounts; Termination.

a. One year prior to the expiration of the Amended Term, the Parties shall commence good faith negotiations to establish PIT and BAT Settlement Payment amounts for APS to run concurrently with any extension of the Leases and Grants. If the Parties are not able to reach agreement upon new PIT and BAT Settlement Payment amounts before expiration of the Amended Term, the Parties will either continue this Restated Agreement in effect with the PIT and BAT Settlement Payment amounts set forth in Section 1 above, or either Party may elect to terminate this Restated Agreement.

b. The Parties recognize and agree that, upon termination or expiration of this Restated Agreement for any reason, (i) each Party has preserved all of its rights and arguments regarding the question of the jurisdictional authority of the Navajo Nation and ONTC to tax the Facilities and/or APS and its successors and assigns based on ownership interests in and operation of the Facilities; (ii) this Restated Agreement shall not in any way be deemed a waiver or amendment of any provisions of any agreement between the Navajo Nation, APS and/or any of the Participants, including but not limited to the Leases and Grants; and (iii) neither Party may assert any claim, demand, damages, action, cause of action, or suit of whatsoever kind and nature, whether known or unknown to the Parties, or whether asserted or unasserted, related, either directly or indirectly, to any and all PIT and BAT tax assessments and taxes, and interest and penalties thereon, that arose or may have arisen while this Restated Agreement was in effect.

13

14. No Third Party Beneficiaries.

Nothing herein, either express or implied is intended or may be construed to confer upon or to give to any person or entity other than the Parties any rights or remedies under or by reason of this Restated Agreement.

15. Limited Responsibility.

The Parties acknowledge and agree that it is their mutual intent that the obligations, representations, warranties and undertakings under this Restated Agreement or as a result of the transactions contemplated by this Restated Agreement are limited to only those expressly set forth herein, and not enlarged by implication, creation of law, or otherwise.

16. Survival.

The provisions of Sections 2(a) and (b), 4, 7 and 13.b of this Restated Agreement survive expiration or termination of this Restated Agreement. Provided that the Restated Agreement remains in effect through the Amended Term, APS’ obligation to make the calendar year 2041 PIT Settlement Payment specified in this Restated Agreement and APS’ obligation to make BAT Settlement Payments for any periods prior to expiration or termination of this Restated Agreement also shall survive expiration or termination of this Restated Agreement.

17. Notices.

Notices shall be deemed to have been given if in writing and (a) hand delivered, (b) delivered by a reputable overnight courier service (such as but not limited to FedEx and UPS), (c) mailed by certified or registered mail, return receipts requested, first class postage prepaid, or (d) transmitted by telecopy or electronic mail, followed within 24 hours by transmittal under option (a), (b) or (c) above addressed as follows:

If to ONTC:

President

The Navajo Nation

P.O. Box 9000

Window Rock, Arizona 86515

With a copy to:

Attorney General

Navajo Nation Department of Justice

P.O. Drawer 2010

Window Rock, Arizona 86515

14

Executive Director

Office of the Navajo Tax Commission

P.O. Box 1903

Window Rock, Arizona 86515

If to APS:

Arizona Public Service Corporation

400 North 5^th Street

Phoenix, Arizona 85004

Attn: Corporate Secretary

With a copy to:

Pinnacle West Capital Corporation

400 North 5th Street

Phoenix, Arizona 85004

Attn: Executive Vice President and General Counsel

or at such other address as the Parties may, from time to time, designate in writing. Service by overnight courier or mail shall be deemed made on the first business day delivery is attempted or upon receipt, whichever is earlier. Service by telecopy or electronic mail shall be deemed made upon confirmed transmission.

18. Effective Date; Effect of this Restated Agreement.

This Restated Agreement is effective upon the date when duly executed by both Parties (the “Effective Date”). It is the Parties’ intention that through the Effective Date of this Restated Agreement, the terms and conditions of the Original Agreement in effect at the date of execution of this Restated Agreement shall continue to govern the Parties’ rights and obligations thereunder. Upon and after the Effective Date of this Restated Agreement, the Parties’ right and obligations shall be governed by the terms and conditions of this Restated Agreement.

15

By signing, the undersigned certify that they have read and agreed to the terms of this Restated Agreement.

ARIZONA PUBLIC SERVICE COMPANY
By:
	Donald G. Robinson	Date
	President
NAVAJO NATION
By:
	Martin Ashley, Executive Director	Date
	Office of the Navajo Tax Commission
APPROVED:
By:
	Louis Denetsosie, Attorney General	Date
	Navajo Nation Department of Justice

16

SETTLEMENT AND CLOSING AGREEMENT

EXHIBIT A

REPORT FOR PIT SETTLEMENT PAYMENT

1. Company Name:

  2.   Mailing Address:

  3.   Contact Name:                               Contact Phone Number:

  4.   Name of Power Generating Facility:

  5.   Name of Plant Operator:

  6.   Location of Facility/Power Plant (Sec. Twp, Rng):

  7.   Term of Lease:                           Lease Expiration Date:

  8.   Percent Participation of Total Plant:

  9.   Number of Units:

Unit #	Capacity (KWH.MWH)	Production (KWH or MWH) for Calendar Year	% Interest	Year Placed in Service
		Total

10.	Type of fuel in use for each unit (coal, gas, etc.):
11.	What is the cost per ton of coal used and purchased by the plant:
12.	Total area of plant site including cooling ponds, coal storage, ash disposal area (acres):
13.	Operating cost($):                      ($/KWH)                     Capital cost($):                      (S/KWH)
14.	Original cost of entire plant($):
	(Original cost means the actual cost of the asset before depreciation/Refer to the attached New Mexico Property Tax Report)
15.	Material & Supplies($):                                      Construction Work In Progress($):                                      (Refer to the attached New Mexico Property Tax Report)        (Refer to the attached New Mexico Property Tax Report)
16.	Book value of entire plant($)
	(Book value means the original cost less depreciation./Refer to the attached New Mexico Property Tax Report.)
17.	What is the % rate of return allowed by the state regulatory agency?
	(Only for those companies whose customer rates are regulated by a corporation commission or public utilities commission)

**Note**

** The amounts reported for items #13 through #16 are reflective of each individual Participant’s ownership share and are not intended to depict Total Plant **

Transmission & Distribution Property Information

1. Transmission Lines

KV Rating Year Built Miles Width of
Right-of-Way Acres

2. Distribution System

Chapter Urban Meters Rural Miles KV Rating Width of
Right-of-Way

3. Substations & Switching Stations

Name Voltage Rating Transformer
KVA Year Built Acres

Additional Information for Operating Report

1. Copy of the previous calendar year annual report or the 10-K filed with the Securities and Exchange Commission

2. Copy of the previous calendar year FERC Form No. 1 (Only for those companies that are required to file this report with FERC)

3. Copy of the New Mexico Property Tax Report

Exhibit B

Calculation of AI (BAT Index) for 2001 and 2002

Price Indexes: Year-to-Year Change

	Electric Power- Other- Mountain			Electric Power- Other -.Pacific			Bituminous Coal and Lignite: West			Natural Gas			Heavy Construction			Unit Labor Cost: Non-Farm Business
1996		105.1	%		99.3	%		102.8	%		136.9	%		101.9	%		100.5	%
1997		101.8	%		102.4	%		99.3	%		111.5	%		101.8	%		100.9	%
1998		100.0	%		100.4	%		96.4	%		82.5	%		99.0	%		102.7	%
1999		99.6	%		100.1	%		98.4	%		108.8	%		101.1	%		102.0	%
2000		99.9	%		104.9	%		97.9	%		170.4	%		103.7	%		103.1	%
2001 (estimated)		105.2	%		111.1	%		103.0	%		110.7	%		99.9	%		103.8	%
2002 (estimated)		99.2	%		97.9	%		99.1	%		52.1	%		97.7	%		100.4	%

Note: Each entry is calculated as the annual average of the appropriate index for the current year divided by the annual average of the same index for the previous year.

BAT Index Calculation

	Revenue Index			Cost Index			Total BAT Index			5-Year Average
1996		103.1	%		101.9	%		102.2	%		—
1997		102.0	%		100.4	%		100.8	%		—
1998		100.1	%		99.6	%		99.7	%		—
1999		99.8	%		100.5	%		100.3	%		—
2000		101.7	%		101.5	%		101.5	%		100.9	%
2001 (estimated*)		107.3	%		103.2	%		104.2	%		101.3	%
2002 (estimated*)		98.7	%		99.2	%		99.1	%		101.0	%

Note:

Revenue Index =

65.24% * (BLS Index: Electric Power — Other — Mountain)

plus 34.76% * (BLS Index: Electric Power — Other — Pacific)

Cost Index =

42.29% * (BLS Index: Bituminous Coal and Lignite: West)

plus 0.86% * (BLS Index: Natural Gas)

plus 7.58% * (BLS Index: Heavy Construction)

plus 49.27% * (BLS Index: Unit Labor Costs: Non-Farm Business)

Total BAT Index = (75% * Cost Index) plus (25% * Revenue Index)

AI Calculation

AI for BAT Settlement Payments 2001 Q3 through 2002 Q2 =
Average of BAT Index for 1996-2000 =	100.9	%
AI (estimated*) for BAT Settlement Payments 2002 Q3 through 2003 Q2 =
AI for 2001 multiplied by average of BAT Index for 1997-2001 =
[100.9%* 101.3%] =	102.2	%	estimated*
AI for BAT Settlement Payments 2003 Q3 through 2004 Q2 =
AI for 2002 multiplied by average of BAT Index for 1998-2002 =
[100.9% * 101.3% * 101.0%] =	103.2	%	estimated*

AI for subsequent year BAT Settlement Payments will follow the same formula.

Note:

* The AI for the 2002 BAT Settlement Payments is estimated using actual BLS data through November 2001 and estimated data for December 2001. This calculation should be updated when complete 2001 BLS data is made available. The AI for the 2003 BAT Settlement Payments is a sample calculation using only data available through March 2002.

Exhibit B (continued)

BLS Price Index Data for AI Calculation

Series Id: PCU1211#214

Industry: Bituminous coal and lignite

Product: West

Base Date: 8112

Year	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		118.7		119.2		119.8		118.5		119.5		122.3		126.4		122.5		119.4		121.6		120.8		120.4			120.8
1996		124.7		125.8		127.6		121.6		127.6		120.9		121.1		126.1		126.2		123.9		121.3		122.4			124.1
1997		121.6		122.6		126.1		129.7		125.8		122.8		125.3		121.7		119.5		121.3		121.9		119.8			123.2
1998		113.8		120.0		118.7		121.8		122.0		120.4		117.4		117.5		118.2		117.0		118.2		120.1			118.8
1999		116.9		118.6		118.5		119.4		116.0		116.7		116.1		115.1		117.3		116.4		115.0		116.6			116.9
2000		114.6		114.7		115.7		113.3		114.6		114.0		115.9		112.7		113.1		114.9		114.1		115.1			114.4
2001		114.6		113.2		114.6		115.9		118.0		116.3		120.1		121.4		119.3		121.5		120.2		[ILLEGIBLE	]		[ILLEGIBLE	]

Series Id: PCU1221#1

Industry: Bituminous coal & lignite surface mining

Product: Unprepared (raw) bituminous coal and lignite shipped from surface operations

Base Date: 0112

2002 [ILLEGIBLE ]  [ILLEGIBLE ]  [ILLEGIBLE ] 

New Coal Index (see Notes, below)

2002 [ILLEGIBLE ]  [ILLEGIBLE ]  [ILLEGIBLE ] 

Series Id: PCU1331#A2

Industry: Crude petroleum, natural gas and natural gas liquids

Product: Natural gas

Base Date: 8406

Year	Jan			Feb			Mar			Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		68.4			62.9			61.3			62.3		63.2		64.8		63.2		56.0		57.1		59.7		63.0		68.9			62.6
1996		78.4			90.7			80.6			87.2		82.7		74.1		82.0		82.9		72.0		70.7		94.6		132.2			85.7
1997		149.9			112.6			73.8			71.0		78.6		83.4		80.6		81.8		91.0		108.8		119.6		95.3			95.5
1998		85.4			76.9			81.2			84.7		85.0		76.9		83.7		77.1		65.6		72.9		78.1		78.3			78.8
1999		70.2			67.6			63.0			69.5		85.9		83.6		86.4		98.0		107.9		97.8		114.2		84.6			85.7
2000		92.1			98.4			99.3			107.8		115.8		159.9		160.2		142.7		166.2		189.5		173.8		247.4			146.1
2001		370.1			246.5			202.8			207.3		191.3		144.2		113.8		113.6		87.4		68.5		107.2		[ILLEGIBLE	]		[ILLEGIBLE	]
2002		[ILLEGIBLE	]		[ILLEGIBLE	]		[ILLEGIBLE	]																					[ILLEGIBLE	]

Series Id: PCUBHVY#

Industry: Other heavy construction

Product: Other heavy construction

Base Date: 8606

Year	Jan			Feb			Mar			Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		128.1			128.6			129.0			129.9		129.9		130.1		130.3		130.4		130.5		130.1		130.3		130.5			129.8
1996		130.6			130.4			131.0			132.0		133.0		133.0		132.3		132.4		132.9		132.9		133.3		133.6			132.3
1997		134.0			134.4			134.5			134.8		135.2		135.0		134.9		135.0		134.9		134.5		134.4		134.0			134.6
1998		133.6			133.3			133.3			133.7		133.8		133.6		133.9		133.5		133.4		133.1		132.6		131.9			133.3
1999		132.4			132.2			132.6			133.7		134.2		134.5		135.7		136.2		136.4		136.1		136.3		136.9			134.8
2000		137.8			139.0			140.0			139.5		139.3		140.5		140.3		139.8		140.8		140.6		140.4		139.7			139.8
2001		140.1			140.3			139.9			140.5		141.9		141.7		139.7		139.7		140.4		137.9		137.1		[ILLEGIBLE	]		[ILLEGIBLE	]
2002		[ILLEGIBLE	]		[ILLEGIBLE	]		[ILLEGIBLE	]																					[ILLEGIBLE	]

Exhibit B (continued)

BLS Price Index Data for AI Calculation

Series Id: PCU4981#148

Industry: Electric power and natural gas utilities

Product: Other — Mountain

Base Date: 9012

Year	Jan			Feb			Mar			Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		112.0			111.9			110.4			110.4		110.5		114.9		115.1		115.1		115.2		115.2		112.0		111.8			112.9
1996		111.7			111.8			110.3			111.5		120.0		123.6		123.7		123.7		123.6		122.9		120.2		120.2			118.6
1997		119.9			118.9			118.6			118.6		121.5		122.9		122.8		122.8		122.8		122.8		118.4		118.2			120.7
1998		118.4			119.1			119.1			119.1		122.0		123.3		122.5		122.2		122.2		122.2		118.9		118.9			120.7
1999		118.3			118.2			118.0			118.0		120.7		122.1		122.0		122.4		122.4		122.1		119.3		119.3			120.2
2000		119.2			119.1			118.2			118.2		118.2		121.9		121.6		121.9		122.1		122.2		119.3		119.8			120.1
2001		119.9			120.0			124.4			124.7		127.6		129.2		129.0		130.0		130.1		129.7		126.3		[ILLEGIBLE	]		[ILLEGIBLE	]
2002		[ILLEGIBLE	]		[ILLEGIBLE	]		[ILLEGIBLE	]																					[ILLEGIBLE	]

Series Id: PCU4981#149

Industry: Electric power and natural gas utilities

Product: Other — Pacific

Base Date: 9012

Year	Jan			Feb			Mar			Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec			Ann Avg
1995		103.6			103.6			102.2			101.5		103.4		113.4		113.5		113.5		113.2		101.5		103.0		103.0			106.3
1996		102.6			102.7			100.3			101.2		103.1		111.2		111.6		111.6		111.5		102.6		104.1		104.1			105.6
1997		104.6			104.7			102.6			104.1		105.5		113.3		114.2		114.2		116.0		105.8		105.9		106.0			108.1
1998		105.8			105.4			103.5			103.5		106.2		114.5		114.6		114.5		115.5		106.0		106.1		106.1			108.5
1999		106.1			105.9			102.5			102.6		104.4		113.8		114.2		114.0		116.1		107.9		107.9		107.0			108.5
2000		106.9			106.9			105.8			106.1		106.9		117.5		121.2		123.4		123.3		115.8		114.9		117.5			113.9
2001		126.0			120.9			122:4			114.0		114.8		134.6		136.0		136.2		136.1		126.5		126.2		[ILLEGIBLE	]		[ILLEGIBLE	]
2002		[ILLEGIBLE	]		[ILLEGIBLE	]		[ILLEGIBLE	]																					[ILLEGIBLE	]

Series Id: PRS85006113

Duration: index, 1992 = 100

Measure: Unit Labor Costs

Sector: Nonfarm Business

Year	Qtr1			Qtr2		Qtr3		Qtr4		Ann Avg
1995		103.1			103.6		104.0		104.0		103.7
1996		103.6			103.7		104.5		104.9		104.2
1997		105.2			104.5		104.7		106.1		105.1
1998		106.7			108.0		108.7		108.6		108.0
1999		109.0			110.5		111.1		110.2		110.2
2000		112.1			112.5		114.0		115.8		113.6
2001		117.2			118.0		118.7		117.9		118.0
2002		[ILLEGIBLE	]								[ILLEGIBLE	]

Notes:

The PCU1211 series was discontinued at the end of 2001. The new series, PCU 1221#1 (which started at 100.0 in Dec. 2001), will be substituted in the AI calculation beginning Jan. 2002. Monthly values for the coal index will be calculated by taking the value of the old coal index on Dec. 2001, 118.4, and multiplying it by the value of the new coal index in each month, then dividing by 100. For example, in Jan. 2002, the value for the coal index used in the AI calculation will be 118.4 * 96.7 /100 = 114.5.

The PPI data is updated monthly and made available at the BLS website:

http://data.bls.gov/labiava/outside.jsp?survey-pc

The labor cost data is updated quarterly and is also available at the BLS website:

http://www.bls.gov./lpc/home.htm

Shaded entries denote prelimenary BLS data

Settlement and Closing Agreement

Exhibit C

Operating Report

Line No.
1.      Revenue Requirement	$	X.XXXX /KWhr
2.	x	AI
3.      Subtotal	$	X.XXXX
4.	x	Net KWhrs
5.      Subtotal	$	XXXXX
Less Deductions
6.      Salaries and/or other compensation paid to members of the Navajo Nation (See Supplemental Schedule I)	$	XXXXX
7.      Purchases of Navajo goods and Services (See Supplemental Schedule II)	$	XXXXX
8.      Payments made to the Navajo Nation government (See Supplemental Schedule III)	$	XXXXX
9.      Standard Deduction (The greater of $125,000 or 10% of line 5.)	$	XXXXX
10.    Total Deductions	$	XXXXX
11.    BAT Settlement Payment Base (Line 5 less Line 10)	$	XXXXX
12.    BAT Settlement Payment Rate	x	5	%
13.    BAT Settlement Payment	$	XXXXX

SETTLEMENT & CLOSING AGREEMENT

EXHIBIT C

SUPPLEMENTAL SCHEDULE I

SALARIES, WAGES, AND OTHER COMPENSATION PAID TO NAVAJOS Page              of              

Company Name (Employer) Quarter Ended

I. 1. Employee Name Navajo Census
Number 2. Salaries or
Wages Paid 3. Other Compensation
(e.g. fringe benefits) 4. Total of Column 2
and Column 3

II.	Total from any additional pages
	Total Salaries and Wages Paid, total column 2
	Total Other Compensation (e.g. fringe benefits), total column 3
III.	Total Salaries, Wages, and Other Compensation, total Col. 4

SETTLEMENT & CLOSING AGREEMENT

EXHIBIT C

SUPPLEMENTAL SCHEDULE II

Purchases of Navajo Goods & Services Page              of              

Company Name (Employer) Quarter Ended

Part A — Detail Purchases of Navajo Goods

Type of Goods Purchased	Vendor Name and Address	Amount
	Total amount

Part B — Detail of Purchases of Navajo Services

Type of Services Purchased	Vendor Name and Address	Amount
	Total amount

SETTLEMENT & CLOSING AGREEMENT

EXHIBIT C

SUPPLEMENTAL SCHEDULE III

Detail of Payments Made to the Navajo Nation Government Page              of              

Company Name (Employer) Quarter Ended

Detail of Payments Made to the Navajo Nation Government

Type of Payment	Payee	Date of Payment	Amount
	Total amount

Restated and Amended Settlement and Closing Agreement

Exhibit D — Sample PIT Calculations

Assumptions:

Original Cost of Facilities on Navajo Nation:

Property Group		Original Cost*
Units 1 - 3			400,000,000
Units 4 - 5			200,000,000
Common			100,000,000
T & D			100,000,000
TOTAL			800,000,000
Current PIT Settlement Payment:		$	6,342,600
Salvage Value = Original Cost x 5%
In-lieu-of-Tax Rate for Salvage = 3%
Sample Calculation for Shut Down of Units:
Assume Permanent Shut Down of Units 1 - 3
Salvage Value of Units 1 - 3 = Original Cost x 5%
	$400M x 5% =		20,000,000
In-lieu-of tax on Units 1 - 3 = Salvage Value x In-lieu-of Tax Rate
	$20M x 3% =		600,000
Calc. of PIT for Remaining Property in Service:
Original Cost of Remaining Property In Service/Total Original Cost
	$400M/800M =		50.00%
PIT on Remaining Property
	0.50 x $6,342,600 =	$	3,171,300
New PIT After Permanent Shut Down of Units 1 - 3:
In-lieu-of tax + PIT on Remaining Property =		$	3,771,300
Sample Calculation if APS Adds a Unit:
Assume APS Adds $1B Unit
Calculation of Increase Factor = Current PIT Settlement Payment/Total Original Cost
	$6,342,600/$800M =		0.7928	%
Calculation of PIT on New Unit = Original Cost of New Unit x Factor
	$1B x 0.007928 =	$	7,928,250
	Existing PIT =	$	6,342,600
New PIT After Addition of Unit		$	14,270,850

* Original Costs are not actual original costs, these costs are for illustration purposes only.

EX-10.3

Exhibit 10.3

February 28, 2011

Cascade Investment, L.L.C.

2365 Carillon Point

Kirkland, WA 98033

Attention: General Counsel

Re: Registration of Certain Shares Issued by PNMR

To Whom it May Concern:

This letter agreement, dated February 28, 2011, between PNM Resources, Inc. (the “Issuer”) and Cascade Investment, L.L.C. (the “Initial Holder”), is made to set forth certain understandings and agreements between the Issuer and the Initial Holder with respect to the Registration Rights Agreement dated as of October 7, 2005 (the “Registration Rights Agreement”) between the Issuer and the Initial Holder. Capitalized terms used but not defined herein are used as defined in the Registration Rights Agreement.

WHEREAS the Initial Holder is currently the record and beneficial owner of (a) 7,019,550 shares of common stock, no par value, of the Issuer (the “Initial Common Stock”) and (b) 477,800 shares of Series A Preferred Stock of the Issuer (the “Preferred Shares”) that are convertible, subject to certain conditions, into 4,778,000 shares of common stock of the Issuer (the “Underlying Common Stock”); and

WHEREAS the Registration Rights Agreement provides for the registration of the Initial Holder’s resale of “Registrable Securities” (as defined in the Registration Rights Agreement) with the U.S. Securities and Exchange Commission (the “SEC”); and

WHEREAS the Initial Holder acknowledges that it is the Issuer’s view that (i) the Initial Common Stock, and (ii) the Underlying Common Stock, if acquired today by the Initial Holder pursuant to the terms of the Preferred Shares and resold by the Initial Purchaser, would not constitute “Restricted Securities” for such purpose because, in the Issuer’s view, the Initial Holder is not currently, and has not at any time in the preceding 90 days been, an “affiliate” of the Issuer for purposes of Rule 144 under the Securities Act of 1933, as amended (“Rule 144”), and that therefore it is the Issuer’s view that it has no obligation under the Registration Rights Agreement to register the resale of the Underlying Common Stock or the Initial Common Stock; and

WHEREAS the Issuer acknowledges that it is the Initial Holder’s view that (i) the determination of “affiliate” status under Rule 144 is fact-specific, and under the facts concerning the Initial Holder’s ownership of the Initial Common Stock and the Preferred Shares, the terms of the Preferred Shares, and the other business relationships between the Initial Holder and the Issuer, it is not possible to determine with certainty at this time whether the Initial Holder is an “affiliate” of the Issuer for purposes of Rule 144, especially since the basis for such a determination under Rule 144 is different from the basis on which a determination of affiliation, control, or similar concepts would be made for purposes of other provisions of federal or state securities law or other regulatory purposes, and (ii) as of the date of this letter agreement, the

Registrable Securities under the Registration Rights Agreement include (a) the Underlying Common Stock for as long as such Underlying Common Stock, if acquired by the Initial Holder pursuant to the terms of the Preferred Shares, would remain a “Restricted Security” (as defined in the Registration Rights Agreement) and (b) the Initial Common Stock, and that therefore it is the Initial Holder’s view that the Issuer is obligated under the Registration Rights Agreement to register the resale of the Underlying Common Stock and the Initial Common Stock; and

WHEREAS, the Issuer and the Initial Holder wish to amend the terms of the Registration Rights Agreement as set forth herein in order to clarify certain matters and for their mutual benefit and to better provide for the orderly disposition by the Initial Holder of the Initial Common Stock and the Underlying Common Stock.

THEREFORE, in consideration of the covenants and agreements contained herein, the Issuer and the Initial Holder agree as follows:

1. The Issuer agrees to prepare and file with the SEC no later than the S-3 Filing Date (as defined below) a registration statement on SEC Form S-3ASR (which may be in the form of a “universal shelf”) covering securities of the Issuer (including shares of common stock) that may be sold by the Issuer and selling security holders from time to time (and following filing of the applicable prospectus supplement contemplated by paragraph 8 below, covering shares of Initial Common Stock and/or Underlying Common Stock that may be sold by the Initial Holder); provided, however, that the S-3 Filing Date shall be extended for such period of time as may be required for the Issuer to obtain and file audited financial statements and/or pro forma financial statements as may be required at the time of such filing under SEC rules for any probable acquisitions or divestitures. Such registration statement shall constitute a Shelf Registration Statement for purposes of the Registration Rights Agreement, and the plan of distribution contained therein shall include (without limitation) sales through underwriters or dealers, sales directly to a limited number of purchasers or to a single purchaser, and sales through agents, in one or more transactions at a fixed price or prices, at market prices or at negotiated prices. As used herein, “S-3 Filing Date” means the earliest to occur of the following: (a) the first Business Day following the date on which the Issuer and the Initial Holder announce a strategic combination transaction currently contemplated by the Issuer, the Initial Holder and a third party involving the operations of Optim Energy LLC (the “Proposed Transaction”), (b) the first Business Day following the date on which the Issuer notifies the Initial Holder that it has abandoned or terminated active discussions of the Proposed Transaction, (c) the third Business Day following the date on which the Initial Holder notifies the Issuer that it has abandoned or terminated active discussions of the Proposed Transaction, and (d) the first Business Day following March 31, 2011.

2. Notwithstanding anything to the contrary contained in the Registration Rights Agreement, the Issuer and the Initial Holder agree that in connection with an underwritten secondary offering of Initial Common Stock and/or Underlying Common Stock pursuant to the Shelf Registration Statement, the Initial Holder will deliver a Sales Notice to the Issuer in such a manner and at such time as is customary for underwritten offerings.

3. The Issuer agrees that it will not offer for sale under the Shelf Registration Statement any equity securities of the Issuer during the 90 day period following the S-3 Filing Date (the “Clear Market Period”); provided, however, that the Clear Market Period shall be extended by the duration of any Deferral Periods exercised by the Issuer during such time.

4. The Initial Common Stock and the Underlying Common Stock shall be treated as “Registrable Securities” under the Registration Rights Agreement, and shall continue to be treated as Registrable Securities until the three year anniversary of the effective date of the Shelf

2

Registration Statement, whereupon all Initial Common Stock and Underlying Common Stock shall cease to be treated as Registrable Securities (the “Registration Period”).

5. Notwithstanding Section 4(v) of the Registration Rights Agreement, the Issuer shall be obligated to participate in up to two underwritten offerings during the Registration Period, provided that each such offering relates to at least 750,000 shares of Common Stock.

6. Notwithstanding Section 5 of the Registration Rights Agreement, the first sentence of the third paragraph of Section 5 relating to Sales Notices shall not be applicable to any sales by the Initial Holder pursuant to the Shelf Registration Statement.

7. Notwithstanding Section 6 of the Registration Rights Agreement,

(a) the Initial Holder shall bear its own expenses for Special Counsel in connection with the preparation and filing of the Shelf Registration Statement and any offerings by the Initial Holder thereunder, and such Special Counsel shall be Cleary Gottlieb Steen & Hamilton LLP; and

(b) the Initial Holder will reimburse the Company for all reasonable and documented out-of-pocket fees and expenses incurred by the Company in connection with a second underwritten offering by the Initial Holder, if any (other than internal expenses of the Company described in the penultimate sentence of Section 6 of the Registration Rights Agreement).

8. In connection with any underwritten offering by the Initial Holder under the Shelf Registration Statement, the Issuer shall prepare, file and provide to the Initial Holder and the applicable underwriters the related preliminary prospectus supplement (if applicable) and final prospectus supplement in such a manner and at such times as are customary for underwritten secondary offerings and as are specified in the related underwriting agreement in order to permit normal “T+3” settlement of such offering. In the case of any other resale by the Initial Holder under the Shelf Registration Statement, the Issuer will prepare, file with the SEC and deliver to the Initial Holder a prospectus supplement relating to such resale no later than 15 days after the Initial Holder delivers a Sales Notice to the Issuer.

9. The rights granted to the Initial Holder under this letter agreement are not transferable to any assignee of the Initial Holder.

10. To the extent this letter agreement is inconsistent with the terms of the Registration Rights Agreement, this letter agreement shall govern and the Registration Rights Agreement shall be deemed amended accordingly. Except for any such inconsistency, the terms of the Registration Rights Agreement are hereby confirmed in all respects and remain in effect. This letter agreement shall be governed by the laws of the State of New York.

11. The Issuer’s obligation under paragraph 1 of this letter agreement to file the Shelf Registration Statement shall become effective only upon the approval of such Shelf Registration Statement by the Board of Directors of the Issuer. In the event such approval is not obtained on or before March 2, 2011, this letter

3

agreement will terminate and the Issuer and the Initial Holder will continue to have all of their rights and obligations under the Registration Rights Agreement that existed immediately prior to the execution of this letter agreement.

IN WITNESS WHEREOF, the parties have executed this letter agreement as of the date first written above.

PNM RESOURCES, INC.
By	/s/ C.N. Eldred

Name:	Charles N. Eldred
Title:	Executive Vice President and Chief Financial Officer

CASCADE INVESTMENT, L.L.C.
By	/s/ Michael Larson

Name:	Michael Larson
Title:	Business Manager

4

EX-10.4

Exhibit 10.4

PNM RESOURCES, INC.

2011 OFFICER SHORT TERM CASH INCENTIVE PLAN

Introduction

PNM Resources, Inc. (the “Company”) has adopted this 2011 Officer Short Term Cash Incentive Plan (the “Plan”) for the purpose of providing annual cash-based incentive awards (each an “Award”) to eligible Officers (as defined below). The Awards payable to Officers under the Plan are intended to qualify as Performance Cash Awards granted pursuant to Section 9.4 of the PNM Resources, Inc. Second Amended and Restated Omnibus Performance Equity Plan (the “PEP”). In the case of Officers who are Covered Employees as defined in the PEP, the Awards also are intended to qualify as Performance-Based Awards granted pursuant to Section 12 of the PEP.

Capitalized terms used in the PEP and not otherwise defined in this Plan document have the meanings given to them in the PEP.

Eligibility

All Officers of the Company and its Affiliates are eligible to participate in the Plan with the exception of the First Choice Power, L.P. (“FCP”) or Optim Energy, LLC (“Optim”) officers, who may be eligible to participate in other incentive plans. For purposes of the Plan, the term “Officer” means any employee who has the title of Chief Executive Officer, President, Executive Vice President, Senior Vice President or Vice President and who is in salary grade H18 or higher.

Award Determinations in General

Awards are based on the Incentive Earnings Per Share (“EPS”) levels for the Performance Period as set forth in Table 1 of Attachment A, the weighting between Corporate and Business Area goals as described in Table 2 of Attachment A and Award levels achieved during the Performance Period as described in Table 3 of Attachment A. The Performance Period began on January 1, 2011 and will end on December 31, 2011.

An Officer’s Award will equal the Officer’s share of the Incentive EPS Award Pool described below. If the Officer’s share of the appropriate Performance Award Pool described below is less than the Officer’s share of the Incentive EPS Award Pool, however, the Officer will receive the smaller amount.

An Officer’s share of an Award Pool will be based upon the amount potentially payable to the Officer for the attained level of performance (Threshold, Target or Maximum), as determined in accordance with Table 3 of Attachment A, as compared to the aggregate amounts potentially payable for the attained level of performance to all of the Officer’s who are entitled to share in that Award Pool. In determining the amount potentially payable to an Officer, the base salaries will be determined as of January 1, 2011. In no event will the amount payable to an Officer exceed the indicated percentage of the Officer’s base salary for the attained performance level as set forth in Table 3 of Attachment A. In addition, in no event will the amount payable to one Officer be increased due to a decrease in the amount payable to any other Officer.

Incentive EPS Award Pool

In order for any Awards to be payable to eligible Officers, the Company must achieve the Threshold EPS level set forth in Table 1 of Attachment A. If the Company does not achieve the Threshold EPS level, no Awards are payable under the Plan to any Officer.

If the Threshold, Target or Maximum EPS levels, as listed in Table 1, are achieved, the aggregate potential Awards payable to the Officers at that level of performance (e.g., the aggregate level of Awards payable at Threshold, Target or Maximum as shown in Table 3 of Attachment A) will make up the “Incentive EPS Award Pool.” If the actual EPS exceeds the minimum level for a performance level by at least $0.01, but is less than the maximum level for that performance level (e.g., if the actual EPS exceeds $0.89 but is less than $0.98), the EPS Award Pool will be increased by using straight-line interpolation between the size of the EPS Award Pool based on the attained level (e.g., Threshold) and the size of the Incentive EPS Award Pool at the next higher level (e.g., Target). The Compensation and Human Resources Committee (the “Committee”) of the Company’s Board of Directors (the “Board”) has the discretion to increase the Incentive EPS Award Pool by an amount less than the amount determined by using straight-line interpolation. The EPS Award Pool is capped by the aggregate Maximum Awards shown in Table 3 for all eligible Officers.

Performance Award Pools

A Corporate Goals Scorecard and Business Area Scorecards listing each performance measure established by the Committee will be maintained by the PNM Resources, Inc. Management Systems Group. As set forth in Table 2 of Attachment A, the performance of the Chief Executive Officer and the Senior Officers (the Executive Vice President and the Senior Vice Presidents) are measured 100% on the Corporate Goals Scorecard. Vice Presidents are measured 60% on the Corporate Goals Scorecard and 40% on the Business Area Goals Scorecard.

The “Performance Award Pool” for each Business Area is the amount that could be paid in the aggregate to the Vice Presidents assigned to that Business Area based on performance alone, determined by using the following multi-step process:

a) Select the Scorecard results from the appropriate Corporate Goal and Business Area Scorecards;

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

c) Then multiply the total Vice President salaries for that Business Area by the Target Award Level as set forth in Table 3 of Attachment A;

d) Then multiply the result of each Scorecard (Step b), expressed as a percentage of Target, by the aggregate base salaries of the Vice Presidents included in that Business Area (Step c); and

e) Sum the results for the Vice President participants.

The Performance Award Pool for the CEO and the Senior Officers will be constructed by using the same process but will be based solely upon the Corporate Goals Scorecard.

Award Approval and Payout Timing

In January 2012, the Committee will determine and certify the level of Awards, if any, payable for the Performance Period in the manner described above. The final Awards calculation and recommendation to the Committee by management will be reviewed and certified by the VP, Human Resources, Director, Audit Services, Director, Management Systems group, and Corporate Controller, respectively. The Board then will approve the CEO’s Award and the Committee will approve the Awards for all other Officers. To the extent Awards are payable under the Plan, the Company will make the payment on or before March 15, 2012 in a single lump sum cash payment subject to applicable withholding.

2

Provisions for a Change in Control

If a Change in Control occurs during the Performance Period and the Officer remains employed by the Company or an Affiliate (for purposes of this section, Optim and FCP are not included as Affiliates) at the end of the Performance Period, the Officer may be entitled to receive an Award for the Performance Period. If the Plan is modified after the occurrence of a Change in Control in a manner that has the effect of reducing the amounts otherwise payable under the Plan, the Officer will receive, at a minimum, an Award equal to 50% of the Maximum Award available under this Plan for the Performance Period.

Pro-rata Awards for Partial Service Periods

In certain circumstances (as set forth below) Officers may or may not be eligible for a Pro-rata Award under the Plan.

The following Officers may be eligible for a Pro-rata Award:

• Officers who are newly hired during the Performance Period and are employed by the Company or an Affiliate (including FCP or Optim) on the day on which Awards are distributed for the Performance Period.

• Employees or Officers who are promoted, transferred or demoted during the Performance Period and are employed by the Company or an Affiliate (including FCP or Optim) on the day on which Awards are distributed for the Performance Period.

• Officers who are on leave of absence for any full months during the Performance Period and are employed by the Company or an Affiliate (including FCP or Optim) on the day on which Awards are distributed for the Performance Period.

• Officers who terminate employment with the Company or an Affiliate during the Performance Period due to Impaction (as defined in the PNM Resources, Inc. Non-Union Severance Pay Plan), Retirement on or after the Officer’s Normal Retirement Date, Change in Control (as defined in the PNM Resources, Inc. Officer Retention Plan) or Disability (as defined in the PNM Resources Executive Savings Plan II).

• Officers who die during the Performance Period, in which case the Award will be paid to the spouse of a married Officer, including a same sex spouse, or the estate of an unmarried Officer.

The following Officers are not eligible for any Award, including a Pro-rata Award:

• Officers who terminate employment with the Company or an Affiliate on or before the date on which Awards are distributed for the Performance Period for any reason other than death, Impaction, Retirement, Change in Control or Disability;

• Officers who elect voluntary separation or Retirement in lieu of termination for performance or misconduct.

If an Officer is eligible for a Pro-rata Award, it will be calculated based on the number of full months that the Officer was actively employed at each eligibility level during the Performance Period compared to the number of full months included in the Performance Period. (Note: Any month in which an Officer is actively on the payroll for at least one day will count as a full month.) Any Pro-rata Awards to which an Officer becomes eligible pursuant to this paragraph will be paid to the Officer in a single lump sum cash payment subject to applicable withholding on or before March 15, 2012.

3

Ethics

The purpose of the Plan is to fairly reward performance achievement. Any Officer who manipulates or attempts to manipulate the Plan for personal gain at the expense of customers, other employees, or the Company or its Affiliates will be subject to disciplinary action, up to and including termination of employment, and will forfeit and be ineligible to receive any Award under the Plan.

Continuation of Employment

This Plan does not confer upon any Officer any right to continue in the employment of the Company or any Affiliate and does not limit the right of the Company or any Affiliate, in its sole discretion, to terminate the employment of any Officer at any time, or in accordance with any written employment agreement the Company and Officer may have.

Amendments

The Committee, in its sole discretion, reserves the right to adjust, amend or suspend the Plan during the Performance Period.

Approved by:

/s/ Alice A. Cobb

Alice A. Cobb, SVP and Chief Administrative Officer

April 29, 2011

Date

4

ATTACHMENT A

Incentive EPS Table

(Table 1)

	PNMR Incentive EPS1
No Award	Less than $0.89
Threshold	Greater than or equal to $0.89 and less than $0.98
Target	Greater than or equal to $0.98 and less than $1.14
Maximum	Greater than or equal to $1.14

Scorecard Weighting Table

(Table 2)

Scorecard Results
Scorecard Level	Corporate Weighting			Business Area Weighting
CEO & Senior Officers		100	%		0	%
Vice Presidents		60	%		40	%

Award Levels Table

(Table 3)

Award Levels	Threshold			Target			Maximum
CEO		36.0	%		90.0	%		180.0	%
Senior Officers		22.0	%		55.0	%		110.0	%
Vice-Presidents		14.0	%		35.0	%		70.0	%

¹  For purposes of the Plan, the Company’s Incentive EPS will be the net earnings, excluding non-recurring items that do not factor into ongoing earnings, divided by the average number of common shares of PNM Resources, Inc. common stock used to calculate diluted EPS as reported in the Company’s 10-K filed for 2011. The Committee’s determination of the Incentive EPS is binding and conclusive.

C-1

EX-10.5

Exhibit 10.5

PNM RESOURCES, INC.

2011 LONG-TERM INCENTIVE TRANSITION PLAN

Introduction

• The 2011 Long-Term Incentive Transition Plan (the “Plan”) provides eligible officers of PNM Resources, Inc. (the “Company”) with the opportunity to earn Performance Share Awards (60% of the total opportunity), Performance Cash Awards (10% of the total opportunity) and time-vested Restricted Stock Rights Awards (30% of the total opportunity).

• The number of Performance Shares and the amount of the Performance Cash earned by an officer for any of the three Performance Periods described below will depend on the officer’s position (e.g., CEO, EVP, SVP or VP) and base salary and the Company’s level of attainment of a Relative TSR Goal and an FFO/Debt Ratio Goal, as described below.

• The number of time-vested Restricted Stock Rights awarded to an officer at the end of each Performance Period will depend on the officer’s position as well as the officer’s base salary.

Performance Periods

• In 2011, the Company will transition from a one-year Performance Period for its long-term incentive to a three-year Performance Period.

• In order to transition to the three-year Performance Period, the total opportunity for 2011 will be earned over three Performance Periods.

• The 2011-1 Performance Period—January 1, 2011 to December 31, 2011.

• The 2011-2 Performance Period—January 1, 2011 to December 31, 2012.

• The 2011-3 Performance Period—January 1, 2011 to December 31, 2013.

Opportunity as Compared to Market Median

• The 2011 Plan begins the gradual process of moving to a long-term incentive opportunity that approximates an aggregate opportunity level in the range of the median of the market.

• The aggregate opportunities available for the 2011-1 Performance Period represent approximately 67% of the median opportunities.

• The aggregate opportunities available for the 2011-2 Performance Period represent approximately 78% of the median opportunities.

• The aggregate opportunities available for the 2011-3 Performance Period represent approximately 89% of the median opportunities.

Performance Goals

• The number of Performance Shares and the amount of Performance Cash that an officer will receive for each of the three Performance Periods will depend on the Company’s level of attainment of a Relative TSR Goal and a FFO/Debt Ratio Goal.

• These Goals and the corresponding Awards are described in the Performance Goal Table (Attachment A).

Performance Share and Performance Cash Award Opportunities

• The Company’s level of attainment (Threshold, Target or Maximum) of the Relative TSR and FFO/Debt Ratio Goals determines the level (Threshold, Target or Maximum) of the officer’s Performance Share and Performance Cash Awards.

• An officer’s Performance Share and Performance Cash Award opportunities also will vary depending on the officer’s position, the officer’s base salary and the Performance Period, all as determined in accordance with the Performance Share and Performance Cash Award Opportunity Tables (Attachment B).

• For purposes of determining the number of Performance Shares to which an officer is entitled at any particular Award Level, the value of one Performance Share shall be equal to the Fair Market Value of one share of the Company’s Stock on the relevant Grant Date and the officer’s base salary shall equal the officer’s base salary as of the first day of the Performance Period.

Time-Vested Restricted Stock Rights Award Opportunities

• At the end of each Performance Period (generally between the next following January 1 and March 15), the Company’s Compensation and Human Resources Committee (the “Committee”) will consider whether to grant time-vested Restricted Stock Rights Awards.

• If the Committee, with the approval of the Company’s Board of Directors (the “Board”), decides to make time-vested Restricted Stock Rights Awards, it must adopt a written resolution to that effect. In the resolution, the Committee will establish the Grant Date for the Awards.

• An officer’s time-vested Restricted Stock Rights Award opportunities will vary depending on the officer’s position and the officer’s base salary, all as determined in accordance with the attached Time-Vested RSR Award Opportunity Table (Attachment C).

• For purposes of determining the number of RSRs to which an officer will be entitled, the value of one RSR shall be equal to the Fair Market Value of one share of the Company’s Stock on the Grant Date specified in the Committee’s resolution and the officer’s base salary shall equal the officer’s base salary on the Grant Date.

Other Provisions

• Only Company officers who have a salary grade of H18 or higher will receive Awards.

• All of the Awards will be made pursuant to the PNM Resources, Inc. Second Amended and Restated Omnibus Performance Equity Plan (the “PEP”).

• All of the Awards will be subject to the standard Terms and Conditions prescribed by the Committee.

• The Grant Date for the Performance Share Awards is March 22, 2011.

2

• Contrary to past practice, a pro rated Award will be provided to an officer who terminates employment during a Performance Period for any reason other than Cause. The pro rated Award will be calculated at the end of the Performance Period based on actual performance during the Performance Period. The pro ration will be made based on the number of months completed by the officer, using the proration rules described in Section 13.1(a)(iv)(2) of the PEP.

• If an individual becomes an officer during a Performance Period, the Committee may grant a pro rata Award to the new officer on such terms and conditions as the Committee deems to be appropriate.

• All Performance Share Awards and Performance Cash Awards payable to officers who are Covered Employees for the Company’s tax year that coincides with the Performance Period are intended to qualify as Performance-Based Awards granted pursuant to Section 12 of the PEP. As a result, all such Awards are subject to the requirements of Section 12 of the PEP.

Approved by:

/s/ Alice A. Cobb

Alice A. Cobb, SVP and Chief Administrative Officer

April 29, 2011

Date

3

Exhibit 10.5

ATTACHMENT A

Performance Goal Table

Goal	Threshold Level1		Target Level		Maximum Level2
Relative TSR3 If the Company’s Relative TSR for any of the three Performance Periods places it in the Threshold, Target or Maximum Level range shown to the right, the Officer will be entitled to receive 60% of the Threshold, Target or Maximum Award as determined in accordance with the Award Opportunity Table for that Performance Period.	Greater than the 35th percentile but not greater than the 50th percentile.		Greater than the 50th percentile but not greater than the 95th percentile.		Greater than the 95th percentile.
FFO/Debt Ratio4 If the Company’s FFO/Debt Ratio on the last day of a Performance Period places it in the Threshold, Target or Maximum Level range for that Performance Period, the Officer will be entitled to receive 40% of the Threshold, Target or Maximum Award as determined in accordance with the Award Opportunity Table for that Performance Period.	2011-1 2011-2 2011-3	At least 18.3% but less than 18.9% At least 18.7% but less than 19.3% At least 21.6% but less than 22.2%	2011-1 2011-2 2011-3	At least 18.9% but less than 20% At least 19.3% but less than 20.4% At least 22.2% but less than 23.3%	2011-1 2011-2 2011-3	At least 20% At least 20.4% At least 23.3%

¹  If the Company’s Relative TSR or FFO/Debt Ratio falls between two Award levels (e.g., the Threshold Level and the Target Level shown in the Performance Goal Table), the number of Performance Shares and the amount of the Performance Cash to which an Officer is entitled will be interpolated between the two Award levels in accordance with uniform procedures prescribed by the Committee.

²  In no event will an Officer receive more than the Maximum Award for an Officer of his or her level as listed in the Award Opportunity Table.

³  The “Relative TSR” Goal refers to the Company’s “Total Shareholder Return” for the Performance Period (expressed as a percentage of the “Beginning Stock Price,” as defined below) as compared to the “Total Shareholder Return” of the other utilities included in the S & P 400 Mid-Cap Utility Index. For this purpose, the Total Shareholder Return of the Company and the other utilities included in the Index will be determined by adding any dividends paid by the Company (or such other utilities) to the appreciation in the value of the Company’s Stock (or the other utilities’ common stock). The appreciation shall be measured by comparing the “Beginning Stock Price” and “Ending Stock Price.” The “Beginning Stock Price” is the average closing price of the Company’s Stock (or the common stock of the other utilities) on the 20 trading days immediately preceding the first day of the Performance Period. The “Ending Stock Price” is the average closing price of the Company’s Stock (or the common stock of the other utilities) on the last 20 trading days of the Performance Period.

⁴  The FFO/Debt Ratio equals PNMR’s funds from operations for the last fiscal year in the performance period divided by PNMR’s total debt outstanding (including any long-term leases and unfunded pension plan obligations) at the end of the performance period. Funds from operations are equal to the net cash flows from operating activities, as reflected on the Consolidated Statement of Cash Flows as reported in the Company’s Form 10-K, adjusted for certain items to ensure the award payments are based on the underlying growth of the core business. The calculation is intended to be consistent with Moody’s calculation of FFO/Debt for the Company.

A-1

Exhibit 10.5

ATTACHMENT B

Performance Share and Performance Cash Award Opportunity Tables

2011-1 Performance Period

Officer Level	Threshold Award	Target Award	Maximum Award
CEO	Performance Shares = 34.25% of base salary Performance Cash = 5.75% of base salary	Performance Shares = 68.5% of base salary Performance Cash = 11.5% of base salary	Performance Shares = 137% of base salary Performance Cash = 23% of base salary
EVP	Performance Shares = 20% of base salary Performance Cash = 3.5% of base salary	Performance Shares = 40% of base salary Performance Cash = 7% of base salary	Performance Shares = 80% of base salary Performance Cash = 14% of base salary
SVP	Performance Shares = 17% of base salary Performance Cash = 3% of base salary	Performance Shares = 34% of base salary Performance Cash = 6% of base salary	Performance Shares = 68% of base salary Performance Cash = 12% of base salary
VP	Performance Shares = 9% of base salary Performance Cash = 1.5% of base salary	Performance Shares = 18% of base salary Performance Cash = 3% of base salary	Performance Shares = 36% of base salary Performance Cash = 6% of base salary

2011-2 Performance Period

Officer Level	Threshold Award	Target Award	Maximum Award
CEO	Performance Shares = 40% of base salary Performance Cash = 6.5% of base salary	Performance Shares = 80% of base salary Performance Cash = 13% of base salary	Performance Shares = 160% of base salary Performance Cash = 26% of base salary
EVP	Performance Shares = 23.5% of base salary Performance Cash = 4% of base salary	Performance Shares = 47% of base salary Performance Cash = 8% of base salary	Performance Shares = 94% of base salary Performance Cash = 16% of base salary
SVP	Performance Shares = 20% of base salary Performance Cash = 3.5% of base salary	Performance Shares = 40% of base salary Performance Cash = 7% of base salary	Performance Shares = 80% of base salary Performance Cash = 14% of base salary
VP	Performance Shares = 10.5% of base salary Performance Cash = 1.75% of base salary	Performance Shares = 21% of base salary Performance Cash = 3.5% of base salary	Performance Shares = 42% of base salary Performance Cash = 7% of base salary

C-1

2011-3 Performance Period

Officer Level	Threshold Award	Target Award	Maximum Award
CEO	Performance Shares = 45.5% of base salary Performance Cash = 7.5% of base salary	Performance Shares = 91% of base salary Performance Cash = 15% of base salary	Performance Shares = 182% of base salary Performance Cash = 30% of base salary
EVP	Performance Shares = 26.5% of base salary Performance Cash = 4.5% of base salary	Performance Shares = 53% of base salary Performance Cash = 9% of base salary	Performance Shares = 106% of base salary Performance Cash = 18% of base salary
SVP	Performance Shares = 22.5% of base salary Performance Cash = 4% of base salary	Performance Shares = 45% of base salary Performance Cash = 8% of base salary	Performance Shares = 90% of base salary Performance Cash = 16% of base salary
VP	Performance Shares = 12% of base salary Performance Cash = 2% of base salary	Performance Shares = 24% of base salary Performance Cash = 4% of base salary	Performance Shares = 48% of base salary Performance Cash = 8% of base salary

A-2

ATTACHMENT C

Time-Vested RSR Award Opportunity Table

Officer Level	Award
CEO	RSRs = 51% of base salary
EVP	RSRs = 30% of base salary
SVP	RSRs = 25.5% of base salary
VP	RSRs = 13.5% of base salary

A-3

EX-10.6

Exhibit 10.6

PNM RESOURCES, INC.

LONG-TERM INCENTIVE PLAN

TERMS AND CONDITIONS

PNM Resources, Inc. (the “Company”) has adopted the PNM Resources, Inc. Second Amended and Restated Omnibus Performance Equity Plan (the “PEP”). Pursuant to the PEP, the Company’s Compensation and Human Resources Committee (the “Committee”) has developed the PNM Resources, Inc. Long-Term Incentive Transition Plan (the “Plan”) pursuant to which eligible officers may receive Performance Share Awards, Performance Cash Awards and time-vested Restricted Stock Rights Awards.

All of the Awards granted under the Plan are made pursuant to the PEP. In addition, all of the Awards are made subject to the provisions of the PEP and these Terms and Conditions. All of the terms of the PEP are incorporated into this document by reference. Capitalized terms used in but not otherwise defined in this document shall have the meanings given to them in the PEP.

1. Performance Share Awards.

(a) Determination of Relative TSR and FFO/Debt Ratio. The Committee will determine the Relative TSR and FFO/Debt Ratio for the Performance Period and the officer’s corresponding Performance Share Award, if any, within 60 days following the end of the Performance Period. The Committee then will certify and submit its determinations with respect to the Relative TSR and FFO/Debt Ratio and the number of Performance Shares to which an officer is entitled to the Board of Directors for review and approval. The Performance Shares to which an officer is entitled shall vest and become payable at the times described below.

(b) Separation from Service; Vesting. Upon an officer’s Separation from Service for any reason other than Cause prior to the end of the Performance Period, the officer shall be entitled to a prorated Award determined at the conclusion of the Performance Period based upon actual performance during the Performance Period. The prorated Award will be determined in accordance with the pro ration rules included in Subsection 13.1(a)(iv)(2) of the PEP. Pursuant to Section 13.5 of the PEP, the Committee has concluded that a prorated Award should be provided regardless of the reason for the officer’s Separation from Service. Upon an officer’s Separation from Service for Cause, all vested and unvested Performance Shares shall be canceled and forfeited immediately.

(c) Form and Timing of Delivery of Stock. All of the Performance Shares awarded and vested pursuant to the Plan will be paid in Stock within the first 90 days of the calendar year following the end of the Performance Period. The Performance Shares granted under this Plan are subject to the requirements of Section 409A of the Code. Accordingly, the restrictions described in Section 20.3 of the PEP apply to the Performance Shares.

(d) Performance-Based Awards. All Performance Share Awards payable to officers who are Covered Employees for the Company’s tax year that coincides with the Performance Period are intended to qualify as Performance-Based Awards granted pursuant to Section 12 of the PEP.

2. Performance Cash Awards.

(a) Determination and Payment of Award. The Committee will determine the Relative TSR and FFO/Debt Ratio for the Performance Period and each officer’s

corresponding Performance Cash Award, if any, within 60 days following the end of the Performance Period. The Committee then will certify and submit its determinations to the Board. The amount payable to an officer will be paid, in one lump sum payment, on or before the March 15 following the end of the calendar year in which the Performance Period ends.

(b) Separation from Service. Upon an officer’s Separation from Service for any reason other than Cause prior to the end of the Performance Period, the officer shall be entitled to a prorated Award determined at the conclusion of the Performance Period based upon actual performance during the Performance Period. The prorated Award shall be based on the number of full months elapsed in the Performance Period as of the date of the officer’s Separation from Service compared to the number of full months included in the Performance Period. Upon an officer’s Separation from Service for Cause, all vested and unvested Performance Cash Awards shall be canceled and forfeited immediately.

(c) Performance-Based Awards. All Performance Cash Awards payable to officers who are Covered Employees for the Company’s tax year that coincides with the Performance Period are intended to qualify as Performance-Based Awards granted pursuant to Section 12 of the PEP.

3. Time-Vested Restricted Stock Rights Awards.

(a) Vesting.

(1) Except as set forth below, the time-vested Restricted Stock Rights shall vest in the following manner: (i) 33% of the time-vested Restricted Stock Rights will vest on the first anniversary of the Grant Date; (ii) an additional 34% of the time-vested Restricted Stock Rights will vest on the second anniversary of the Grant Date; and (iii) the final 33% of the time-vested Restricted Stock Rights will vest on the third anniversary of the Grant Date.

(2) Upon an officer’s involuntary or voluntary Separation from Service for any reason other than those set forth in Section 3(a)(3), the time-vested Restricted Stock Rights, if not previously vested, shall be canceled and forfeited immediately.

(3) Upon an officer’s Separation from Service due to death, Disability, Retirement, Impaction or Change in Control, any unvested time-vested Restricted Stock Rights shall become 100% vested in accordance with the applicable provisions of the PEP.

(b) Form and Timing of Delivery of Certificate. All of the time-vested Restricted Stock Rights awarded pursuant to this Plan will be paid in Stock in accordance with the following provisions:

(1) If any time-vested Restricted Stock Rights vest in accordance with Section 3(a)(1), the officer will receive the Stock payable with respect to such vested Restricted Stock Rights within 90 days following the dates on which the Restricted Stock Rights vest.

(2) If any time-vested Restricted Stock Rights vest in accordance with Section 3(a)(3), the officer will receive the Stock payable with respect to such Restricted Stock Rights within 90 days following the date of the officer’s Separation from Service.

(3) If the 90-day period during which payments may be made pursuant to Section 3(a)(1) or (3) begins in one calendar year and ends in another, the officer will receive the Stock in the second calendar year.

2

(4) All Stock will be awarded in accordance with the requirements of Section 409A of the Code and Section 20.3 of the PEP.

4. Adjustments. Neither the existence of the Plan nor the Awards shall affect, in any way, the right or power of the Company to make or authorize: any or all adjustments, recapitalizations, reorganizations, or other changes in the Company’s capital structure or its business; or any merger or consolidation of the Company; or any corporate act or proceeding, whether of a similar character or otherwise; all of which, and the resulting adjustments in, or impact on, the Awards are more fully described in Section 5.3 of the PEP.

5. Dividend Equivalents. An officer will not be entitled to receive a dividend equivalent for any of the Performance Shares or time-vested Restricted Stock Rights granted under the Plan.

6. Status of Plan and Administration. The Plan and these Terms and Conditions shall at all times be subject to the terms and conditions of the PEP and shall in all respects be administered by the Committee in accordance with the terms of and as provided in the PEP. The Committee shall have the sole and complete discretion with respect to the interpretation of the Plan, these Terms and Conditions and the PEP, and all matters reserved to it by the PEP. The decisions of the majority of the Committee shall be final and binding upon an officer and the Company. In the event of any conflict between the terms and conditions of the Plan or these Terms and Conditions and the PEP, the provisions of the PEP shall control.

7. Waiver and Modification. The provisions of the Plan and these Terms and Conditions may not be waived or modified unless such waiver or modification is in writing signed by an authorized representative of the Committee.

8. Amendment or Suspension. The Committee, in its sole discretion, reserves the right to adjust, amend or suspend the Plan and these Terms and Conditions during the Performance Period except as otherwise provided in the PEP.

IN WITNESS WHEREOF, the Committee has caused these Terms and Conditions to be executed on March 22, 2011, by a duly authorized representative.

PNM RESOURCES, INC.
By	/s/ Alice A. Cobb
	Alice A. Cobb
	Senior Vice President and
	Chief Administrative Officer

3

EX-12.1

Exhibit 12.1

PNM RESOURCES, INC. AND SUBSIDIARIES

Ratio of Earnings to Fixed Charges

(In thousands, except ratio)

	Three Months Ended March 31, 2011			Year Ended December 31,
				2010			2009			2008			2007			2006
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	30,132		$	123,633		$	123,833		$	134,958		$	124,299		$	135,819
Amortization of debt premium, discount and expenses		913			4,627			5,430			6,386			6,566			4,729
Interest from discontinued operations (including capitalized interest)		—			—			1,027			13,758			12,546			11,790
Estimated interest factor of lease rental charges		1,726			6,888			7,034			7,894			8,804			7,124
Preferred dividend requirements of subsidiary		195			1,075			759			689			556			798
Total Fixed Charges	$	32,966		$	136,223		$	138,083		$	163,685		$	152,771		$	160,260
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	29,458		$	(63,379	)	$	94,751		$	(388,381	)	$	63,112		$	164,018
(Earnings) loss of equity investee		—			15,223			30,145			29,687			(7,581	)		—
Earnings (loss) from continuing operations before income taxes, non-controlling interest, and investee earnings		29,458			(48,156	)		124,896			(358,694	)		55,531			164,018
Fixed charges as above		32,966			136,223			138,083			163,685			152,771			160,260
Interest capitalized		(572	)		(3,401	)		(7,743	)		(8,849	)		(10,740	)		(6,503	)
Non-controlling interest in earnings of Valencia		(3,183	)		(13,563	)		(11,890	)		(7,179	)		—			—
Preferred dividend requirements of subsidiary		(195	)		(1,075	)		(759	)		(689	)		(556	)		(798	)
Earnings Available for Fixed Charges	$	58,474		$	70,028		$	242,587		$	(211,726	)	$	197,006		$	316,977
Ratio of Earnings to Fixed Charges		1.77			0.51	1		1.76			N/M	2		1.29			1.98

¹ The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $66.2 million for the year ended December 31, 2010. Earnings (loss) from continuing operations before income taxes and non-controlling interest includes a pre-tax loss of $188.2 million due to the impairment of PNMR’s investment in an equity investee. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 1.90.

² The ratio of earnings to fixed charges for the year ended December 31, 2008 is not meaningful since earnings available for fixed charges is negative. The shortfall in the earnings available to achieve a ratio of earnings to fixed charges of 1.00 amounted to $375.4 million for the year ended December 31, 2008.

EX-12.2

Exhibit 12.2

PNM RESOURCES, INC. AND SUBSIDIARIES

Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

(In thousands, except ratio)

	Three Months Ended March 31, 2011			Year Ended December 31,
				2010			2009			2008			2007			2006
Combined fixed charges and preferred stock dividends, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	30,132		$	123,633		$	123,833		$	134,958		$	124,299		$	135,819
Amortization of debt premium, discount and expenses		913			4,627			5,430			6,386			6,566			4,729
Interest from discontinued operations (including capitalized interest)		—			—			1,027			13,758			12,546			11,790
Estimated interest factor of lease rental charges		1,726			6,888			7,034			7,894			8,804			7,124
Preferred dividend requirements of subsidiary		195			1,075			759			689			556			798
Total Fixed Charges		32,966			136,223			138,083			163,685			152,771			160,260
Preferred stock dividend requirements		882			4,865			3,433			780			—			—
Total Combined Fixed Charges and Preferred Stock Dividends	$	33,848		$	141,088		$	141,516		$	164,465		$	152,771		$	160,260
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	29,458		$	(63,379	)	$	94,751		$	(388,381	)	$	63,112		$	164,018
(Earnings) loss of equity investee		—			15,223			30,145			29,687			(7,581	)		—
Earnings (loss) from continuing operations before income taxes, non-controlling interest, and investee earnings		29,458			(48,156	)		124,896			(358,694	)		55,531			164,018
Fixed charges as above		32,966			136,223			138,083			163,685			152,771			160,260
Interest capitalized		(572	)		(3,401	)		(7,743	)		(8,849	)		(10,740	)		(6,503	)
Non-controlling interest in earnings of Valencia		(3,183	)		(13,563	)		(11,890	)		(7,179	)		—			—
Preferred dividend requirements of subsidiary		(195	)		(1,075	)		(759	)		(689	)		(556	)		(798	)
Earnings Available for Combined Fixed Charges and Preferred Stock Dividends	$	58,474		$	70,028		$	242,587		$	(211,726	)	$	197,006		$	316,977
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends		1.73			0.50	1		1.71			N/M	2		1.29			1.98

¹  The shortfall in the earnings available for combined fixed charges and preferred stock divendends to achieve a ratio of earnings to combined fixed charges and preferred stock dividends of 1.00 amounted to $71.1 million for the year ended December 31, 2010. Earnings (loss) from continuing operations before income taxes and non-controlling interest includes a pre-tax loss of $188.2 million due to the impairment of PNMR’s investment in an equity investee. If that loss were excluded, the ratio of earnings to combined fixed charges and preferred stock dividends would have been 1.83.

²  The ratio of earnings to combined fixed charges and preferred stock dividends for the year ended December 31, 2008 is not meaningful since earnings available for combined fixed charges and preferred stock dividends is negative. The shortfall in the earnings available for combined fixed charges and preferred stock dividends to achieve a ratio of earnings to combined fixed charges and preferred stock dividends of 1.00 amounted to $376.2 million for the year ended December 31, 2008.

EX-12.3

Exhibit 12.3

PUBLIC SERVICE COMPANY OF NEW MEXICO

Ratio of Earnings to Fixed Charges

(In thousands, except ratio)

	Three Months Ended March 31, 2011			Year Ended December 31,
				2010			2009			2008			2007			2006
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	17,994		$	73,423		$	73,104		$	72,427		$	58,045		$	49,379
Amortization of debt premium, discount and expenses		306			1,274			1,336			4,345			4,618			2,871
Interest from discontinued operations (including capitalized interest)		—			—			1,027			13,758			12,546			11,790
Estimated interest factor of lease rental charges		1,027			4,103			4,517			4,553			4,661			4,337
Total Fixed Charges	$	19,327		$	78,800		$	79,984		$	95,083		$	79,870		$	68,377
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	9,359		$	107,288		$	45,627		$	(69,324	)	$	34,611		$	89,657
Fixed charges as above		19,327			78,800			79,984			95,083			79,870			68,377
Non-controlling interest in earnings of Valencia		(3,183	)		(13,563	)		(11,890	)		(7,179	)		—			—
Interest capitalized		(362	)		(2,811	)		(6,067	)		(7,363	)		(10,033	)		(5,257	)
Earnings Available for Fixed Charges	$	25,141		$	169,714		$	107,654		$	11,217		$	104,448		$	152,777
Ratio of Earnings to Fixed Charges		1.30			2.15			1.35			0.12	1		1.31			2.23

¹  The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $83.9 million for the year December 31, 2008.

EX-12.4

Exhibit 12.4

TEXAS-NEW MEXICO POWER COMPANY

Ratio of Earnings to Fixed Charges

(In thousands, except ratio)

	Three Months Ended March 31, 2011			Year Ended December 31,
				2010			2009			2008			2007			2006
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	6,978		$	28,632		$	25,609		$	17,861		$	23,523		$	27,374
Amortization of debt premium, discount and expenses		440			2,683			3,355			1,504			1,925			1,695
Estimated interest factor of lease rental charges		340			1,246			831			571			844			367
Total Fixed Charges	$	7,758		$	32,561		$	29,795		$	19,936		$	26,292		$	29,436
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes	$	6,741		$	26,026		$	20,151		$	2,335		$	29,055		$	17,905
Fixed charges as above		7,758			32,561			29,795			19,936			26,292			29,436
Interest capitalized		(119	)		(158	)		(1,144	)		(1,025	)		(332	)		(209	)
Earnings Available for Fixed Charges	$	14,380		$	58,429		$	48,802		$	21,246		$	55,015		$	47,132
Ratio of Earnings to Fixed Charges		1.85			1.79			1.64			1.07			2.09			1.60

EX-31.1

PNM Resources

Alvarado Square

Albuquerque, NM 87158

EXHIBIT 31.1

CERTIFICATION

I, Patricia K. Collawn, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2011	By:	/s/ Patricia K. Collawn
		Patricia K. Collawn
		President and Chief Executive Officer
		PNM Resources, Inc.

EX-31.2

PNM Resources

Alvarado Square

Albuquerque, NM 87158

EXHIBIT 31.2

CERTIFICATION

I, Charles N. Eldred, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2011	By:	/s/ Charles N. Eldred
		Charles N. Eldred
		Executive Vice President and
		Chief Financial Officer PNM Resources, Inc.

EX-31.3

Public Service Company of New Mexico

Alvarado Square

Albuquerque, NM 87158

EXHIBIT 31.3

CERTIFICATION

I, Patricia K. Collawn, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2011	By:	/s/ Patricia K. Collawn
		Patricia K. Collawn
		President and Chief Executive Officer
		Public Service Company of New Mexico

EX-31.4

Public Service Company of New Mexico

Alvarado Square

Albuquerque, NM 87158

EXHIBIT 31.4

CERTIFICATION

I, Charles N. Eldred, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2011	By:	/s/ Charles N. Eldred
		Charles N. Eldred
		Executive Vice President and
		Chief Financial Officer Public Service Company of New Mexico

EX-31.5

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 31.5

CERTIFICATION

I, Patricia K. Collawn, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2011	By:	/s/ Patricia K. Collawn
		Patricia K. Collawn
		President and Chief Executive Officer
		Texas-New Mexico Power Company

EX-31.6

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 31.6

CERTIFICATION

I, Thomas G. Sategna, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2011	By:	/s/ Thomas G. Sategna
		Thomas G. Sategna
		Vice President and Controller
		Texas-New Mexico Power Company

EX-32.1

PNM Resources

Alvarado Square

Albuquerque, NM 87158

www.pnmresources.com

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended March 31, 2011, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on May 6, 2011 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 6, 2011	By:	/s/ Patricia K. Collawn
		Patricia K. Collawn
		President and Chief Executive Officer
		PNM Resources, Inc.
	By:	/s/ Charles N. Eldred
		Charles N. Eldred
		Executive Vice President and
		Chief Financial Officer

EX-32.2

Public Service Company of New Mexico

Alvarado Square

Albuquerque, NM 87158

EXHIBIT 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended March 31, 2011, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on May 6, 2011 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 6, 2011	By:	/s/ Patricia K. Collawn
		Patricia K. Collawn
		President and Chief Executive Officer
		Public Service Company of New Mexico
	By:	/s/ Charles N. Eldred
		Charles N. Eldred
		Executive Vice President and
		Chief Financial Officer

EX-32.3

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 32.3

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended March 31, 2011, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on May 6, 2011 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 6, 2011	By:	/s/ Patricia K. Collawn
		Patricia K. Collawn
		President and Chief Executive Officer
		Texas-New Mexico Power Company
	By:	/s/ Thomas G. Sategna
		Thomas G. Sategna
		Vice President, Controller
		Texas-New Mexico Power Company