UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_________________________________________________

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, ~~2011~~2012

CommissionFile Number	Names of Registrants, State of Incorporation,Address and Telephone Number	I.R.S. EmployerIdentification No.
001-32462	PNM Resources, Inc.(A New Mexico Corporation)~~Alvarado~~414 ~~SquareAlbuquerque~~Silver Ave. SWAlbuquerque, New Mexico ~~87158~~87102-3289(505) 241-2700	85-0468296
001-06986	Public Service Company of New Mexico(A New Mexico Corporation)~~Alvarado~~414 ~~SquareAlbuquerque~~Silver Ave. SWAlbuquerque, New Mexico ~~87158~~87102-3289(505) 241-2700	85-0019030
002-97230	Texas-New Mexico Power Company(A Texas Corporation)577 N. Garden Ridge Blvd.Lewisville, Texas 75067(972) 420-4189	75-0204070

Securities Registered Pursuant To Section 12(b) Of The Act:



Registrant	Title of Each Class	Name of Each Exchange on Which Registered
PNM Resources, Inc.	Common Stock, no par value	New York Stock Exchange

Securities Registered Pursuant To Section 12(g) Of The Act:



Registrant		Title of Each Class
Public Service Company of New Mexico		1965 Series, 4.58% Cumulative Preferred Stock
		($100 stated value without sinking fund)

Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.



PNM Resources, Inc. (“PNMR”)	YES ü	NO
Public Service Company of New Mexico (“PNM”)	YES	NO ü
Texas-New Mexico Power Company (“TNMP”)	YES	NO ü

Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.



PNMR	YES	NO ü
PNM	YES	NO ü
TNMP	YES ü	NO

Table of Contents

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.



PNMR	YES ü	NO
PNM	YES ü	NO
TNMP	YES	NO ü

(NOTE: As a voluntary filer, not subject to the filing requirements, TNMP filed all reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.)

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).



PNMR	YES ü	NO
PNM	YES ü	NO
TNMP	YES ü	NO

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10–K or any amendment to this Form 10–K. ü

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 acceleratedfiler Acceleratedfiler Non-acceleratedfiler Smaller ReportingCompany PNMR ü __ PNM __ ü TNMP __ ü

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

As of February 22, ~~2012~~2013, shares of common stock outstanding were.:



PNMR	79,653,624
PNM	39,117,799
TNMP	6,358

On June 3029, ~~2011~~2012, the aggregate market value of the voting common stock held by non-affiliates of PNMR as computed by reference to the New York Stock Exchange composite transaction closing price of $1619.7454 per share reported by The Wall Street Journal, was $1,~~450~~556,~~908~~431,~~933~~813. PNM and TNMP have no common stock held by non-affiliates.

PNM AND TNMP MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (I) (1) (a) AND (b) OF FORM 10-K AND ARE THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT PURSUANT TO GENERAL INSTRUCTION (I) (2).

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the following document are incorporated by reference into Part III of this report:

Proxy Statement to be filed by PNMR with the SEC pursuant to Regulation 14A relating to the annual meeting of stockholders of PNMR to be held on May 159, ~~2012~~2013.

This combined Form 10-K 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-K 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-K that relate to each other registrant are not incorporated by reference therein.

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

INDEX

			Page
GLOSSARY			iv
PART I
ITEM 1. BUSINESS			A- 1
THE COMPANY			A- 1
WEBSITES			A- 1
OPERATIONS			A- 5
OPERATIONS & REGULATION			A- 2
REGULATED OPERATIONS
PNM Electric			A- 2
PNM			A- 2
TNMP Electric			A- 4
TNMP			A- 4
PNM Gas			A- 5
COMPETITIVE BUSINESSES
First Choice			A- 5
Optim Energy			A- 6
CORPORATE AND OTHER			A- 6
SOURCES OF POWER			A- 76
FUEL AND WATER SUPPLY			A- 9
ENVIRONMENTAL MATTERS			A- 1110
COMPETITION			A- 11
EMPLOYEES			A- 11
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS			A- 1211
SECURITIES ACT DISCLAIMER			A- 12
ITEM 1A. RISK FACTORS			A- 1312
ITEM 1B. UNRESOLVED STAFF COMMENTS			A- 19
ITEM 2. PROPERTIES			A- 19
ITEM 3. LEGAL PROCEEDINGS			A- 19
ITEM 4. MINE SAFETY DISCLOSURES			A- 20
SUPPLEMENTAL ITEM – EXECUTIVE OFFICERS OF PNM RESOURCES, INC.			A- 20
PART II
ITEM 5. MARKET FOR PNMR’S COMMON EQUITY, RELATED STOCKHOLDER			A- 21
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA			A- 2322
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			A- 2726
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK			A- 52
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			B- 1
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON			C- 1
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING			C- 1
ACCOUNTING AND FINANCIAL DISCLOSURE
AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES			C- 1
ITEM 9B. OTHER INFORMATION			C- 2
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF PNMR AND CORPORATE GOVERANCE			C- 2
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERANCE			C- 2
ITEM 11. EXECUTIVE COMPENSATION			C- 2
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			C- 2
AND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,			C- 2
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR			C- 2
AND DIRECTOR INDEPENDENCE
INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES			C- 2
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES			D-01
SIGNATURES			E-1

iii

Table of Contents

GLOSSARY

Definitions:
ABO		Accumulated Benefit Obligation
Afton		Afton Generating Station
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
Altura		Optim Energy Twin Oaks, LP.
AMS		Advanced Meter System
AOCI		Accumulated Other Comprehensive Income
APBO		Accumulated Postretirement Benefit Obligation
APS		Arizona Public Service Company, which is the operator and a co-owner of PVNGS and Four Corners
ARO		Asset Retirement Obligation
BACT		Best Available Control Technology
BART		Best Available Retrofit Technology
BHP		BHP Billiton, Ltd, the ~~Parent~~parent of SJCC
Board		Board of Directors of PNMR
BTU		British Thermal Unit
CAA		Clean Air Act
Cal PX		California Power Exchange
Cal ISO		California Independent System Operator
Cascade		Cascade Investment, L.L.C.
CCB		Coal Combustion Byproducts
CO2		Carbon Dioxide
Continental		Continental Energy Systems, L.L.C.
CRHC		Cap Rock Holding Corporation, a subsidiary of Continental
CTC		Competition Transition Charge
Decatherm		Million BTUs
D.C. Circuit		United States Court of Appeals for the District of Columbia Circuit
Delta		Delta-Person Generating Station
DOE		United States Department of Energy
DOI		United States Department of Interior
ECJV		ECJV Holdings, LLC
EIB		New Mexico Environmental Improvement Board
EIP		Eastern Interconnection Project
EPA		United States Environmental Protection Agency
EPE		El Paso Electric
ERCOT		Electric Reliability Council of Texas
ESPP		Employee Stock Purchase Plan
ESA		Endangered Species Act
Exchange Act		Securities Exchange Act of 1934
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIP		Federal Implementation Plan
First Choice		FCP Enterprises, Inc. and Subsidiaries
Four Corners		Four Corners Power Plant
FPL		FPL Energy New Mexico Wind, LLC
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
IBEW		International Brotherhood of Electrical Workers, Local 611
IRP		Integrated Resource Plan
IRS		Internal Revenue Service
KW		Kilowatt
KWh		Kilowatt Hour

Table of Contents

IRS		Internal Revenue Service
ISO		Independent System Operator
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
NAAQS		National Ambient Air Quality Standards
Navajo Acts		Navajo Nation Air Pollution Prevention and Control Act, Navajo Nation Safe Drinking Water Act, and Navajo Nation Pesticide Act
NDT		Nuclear Decommissioning Trusts for PVNGS
NEC		Navopache Electric Cooperative, Inc.
NERC		North American Electric Reliability Council
Ninth Circuit		United States Court of Appeals for the Ninth Circuit
NMAG		New Mexico Attorney General
NMED		New Mexico Environment Department
NMGC		New Mexico Gas Company, a subsidiary of Continental
NMIEC		New Mexico Industrial Energy Consumers Inc.
NMPRC		New Mexico Public Regulation Commission
NOx		Nitrogen Oxides
NOI		Notice of Inquiry
NOPR		Notice of Proposed Rulemaking
NRC		United States Nuclear Regulatory Commission
NSPS		New Source Performance Standards
NSR		New Source Review
O&M		Operations and Maintenance
OCI		Other Comprehensive Income
OPEB		Other Post Employment Benefits
Optim Energy		Optim Energy, LLC, a limited liability company, formerly known as EnergyCo, LLC
OSM		United States Office of Surface Mining Reclamation and Enforcement
PBO		Projected Benefit Obligation
PCRBs		Pollution Control Revenue Bonds
PGAC		Purchased Gas Adjustment Clause
PG&E		Pacific Gas and Electric Co.
PNM		Public Service Company of New Mexico and Subsidiaries
PNM Facility		PNM’s Unsecured Revolving Credit Facility, replaced by the PNM Revolving Credit Facility in 2011
PNM Revolving Credit Facility		PNM's $400.0 Million Unsecured Revolving Credit Facility
PNMR		PNM Resources, Inc. and Subsidiaries
PNMR Facility		PNMR’s Unsecured Revolving Credit Facility, replaced by the PNMR Revolving Credit Facility in 2011
PNMR Revolving Credit Facility		PNMR's $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan Agreement		PNMR’s $100 Million Unsecured Term Loan Facility
PPA		Power Purchase Agreement
PSD		Prevention of Significant Deterioration
PUCT		Public Utility Commission of Texas
PV		Photovoltaic
PVNGS		Palo Verde Nuclear Generating Station
RCRA		Resource Conservation and Recovery Act
RCT		Reasonable Cost Threshold
REA		New Mexico's Renewable Energy Act of 2004
REC		Renewable Energy Certificates
REP		Retail Electricity Provider
RMC		Risk Management Committee

Table of Contents

PVNGS		Palo Verde Nuclear Generating Station
RCRA		Resource Conservation and Recovery Act
RCT		Reasonable Cost Threshold
REA		New Mexico's Renewable Energy Act of 2004
REC		Renewable Energy Certificates
REP		Retail Electricity Provider
RFP		Request for Proposal
RMC		Risk Management Committee
RPS		Renewable Energy Portfolio Standard
SCE		Southern California Edison Company
SCPPA		Southern California Public Power Authority
SCR		Selective Catalytic Reduction
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
SJCC		San Juan Coal Company
SJGS		San Juan Generating Station
SNCR		Selective Non-Catalytic Reduction
SO2		Sulfur Dioxide
SPS		Southwestern Public Service Company
SRP		Salt River Project
S&P		Standard and Poor’s Ratings Services
TCEQ		Texas Commission on Environmental Quality
TECA		Texas Electric Choice Act
Term Loan Agreement		PNM’s $300 Million Unsecured Delayed Draw Term Loan Facility
Tenth Circuit		United States Court of Appeals for the Tenth Circuit
TNMP		Texas-New Mexico Power Company and Subsidiaries
TNMP 2011 Term Loan Agreement		TNMP's $50 Million Secured Term Loan
TNMP Revolving Credit Facility		TNMP’s $75 Million Revolving Credit Facility
TNP		TNP Enterprises, Inc. and Subsidiaries
Tri-State		Tri-State Generation and Transmission Association, Inc.
Tucson		Tucson Electric Power Company
Twin Oaks		Assets of Twin Oaks Power, L.P. and Twin Oaks Power III, L.P.
UAMPS		Utah Associated Municipal Power System
Valencia		Valencia Energy Facility
VaR		Value at Risk
WACC		Weighted Average Cost of Capital
WEG		WildEarth Guardians
WSPP		Western Systems Power Pool

Table of Contents

PART I


ITEM 1.	BUSINESS

THE COMPANY

~~Corporate~~ Overview

PNMR is an investor-owned holding company of utilities providing electricity and energy efficiency products and services in New Mexico and Texas. With PNMR's exit from its unregulated businesses in 2011 ~~and PNM's sale of its natural gas utility in early 2009~~, PNMR is now fully repositioned as a holding company of regulated electric utilities focused on achieving the following strategic goals:


•	Earning authorized returns on its regulated businesses


•	Continuing to improve credit ratings


•	Providing a top quartile total return to investors

PNMR's success in accomplishing these strategic goals is highly dependent on continued favorable regulatory treatment for its regulated utilities. Both PNM and TNMP seek cost recovery for their investments through general rate cases and various rate riders. The PUCT has approved mechanisms that allow for recovery of capital invested in transmission and distribution projects without having to file a general rate case. ~~This~~In ~~allows~~2011, ~~for~~PNM ~~more~~and ~~timely~~TNMP ~~recovery~~completed ofgeneral ~~amounts~~rate ~~invested~~proceedings inbefore ~~TNMP's~~their ~~systems~~state regulators. ~~Both~~In August 2012, PNM implemented a rate rider to collect renewable energy procurement costs that are not otherwise being collected in rates. On January 2, 2013, FERC approved a settlement for an increase in rates PNM charges its transmission customers and, ~~TNMP~~in ~~have~~December ~~recently~~2012, ~~completed~~PNM filed for an additional increase in rates charged to those customers based on a formula rate ~~proceedings~~methodology, ~~before~~which ~~their~~is ~~state~~pending ~~regulators~~before FERC. PNM has ~~two~~also ~~rate~~reached ~~cases~~a settlement for an increase in rates charged to its largest firm-requirements wholesale customer, which is pending before FERC. In September 2012, TNMP received PUCT approval for an increase in its rates to reflect increases in its transmission cost of service. Additional information about ~~all~~ rate filings is provided in Note 17.

PNMR's common stock trades on the New York Stock Exchange under the symbol PNM. PNMR was incorporated in the State of New Mexico in 2000.

Other Information

These filings for PNMR, PNM, and TNMP include disclosures for each entity. For discussion purposes, this report will use the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP will be indicated as such. A reference to “MD&A” in this report refers to Part II, Item 7. - Management's Discussion and Analysis of Financial Condition and Results of Operations. A reference to a “Note” refers to the accompanying Notes to Consolidated Financial Statements.

Financial information relating to amounts of sales, revenue, net income, and total assets of reportable segments is contained in MD&A and Note 32.

WEBSITES

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

Our Internet addresses are:


•	PNMR: www.pnmresources.com


•	PNM: www.pnm.com


•	TNMP: www.tnmp.com

The contents of these websites are not a part of this Form 10-K. The SEC filings of PNMR, PNM, and TNMP, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are accessible free of charge on the PNMR website as soon as reasonably practicable after they are filed with, or furnished to, the SEC. These reports are also available in print upon request from PNMR free of charge.

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Table of Contents

Also available on the Company's website at www.pnmresources.com/investors/governance.~~com~~cfm and in print upon request from any shareholder are our:


•	Corporate Governance Principles


•	Code of Ethics (Do the Right Thing-Principles of Business Conduct)


•	Charters of the Audit and Ethics Committee, Nominating and Governance Committee, Compensation and Human Resources Committee, and Finance Committee

The Company will post amendments to or waivers from its code of ethics (to the extent applicable to the Company's executive officers and directors) on its website.

OPERATIONS AND REGULATION

Regulated Operations

PNM ~~Electric~~

PNM ~~Electric~~ is an electric utility that provides electric generation, transmission, and distribution service to its rate-regulated customers. In New Mexico, the utility's retail electric service territory covers a large area of north central New Mexico, including the cities of Albuquerque, Rio Rancho, and Santa Fe, and certain other areas of southern New Mexico. PNM ~~Electric~~ also provides electricity to firm-requirements wholesale customers in New Mexico and Arizona. Service to retail electric customers is subject to the jurisdiction of the NMPRC. Service to wholesale customers is regulated by FERC. Regulation encompasses the utility's electric rates, service, accounting, issuances of securities, construction of major new generation, transmission, and distribution facilities, and other matters.

Other services provided by PNM ~~Electric~~ include transmission services to third parties as well as the generation and sale of electricity into the wholesale market, which services are regulated by FERC. The utility owns or leases transmission lines, interconnected with other utilities in New Mexico, Texas, Arizona, Colorado, and Utah. The largest retail electric customer served by PNM ~~Electric~~ accounted for 3.56% of the utility's revenues for the year ended December 31, ~~2011~~2012. PNM was incorporated in the State of New Mexico in 1917.

Rate Proceedings

Customer rates for retail electric service are set by the NMPRC. PNM ~~Electric~~ made a general rate case ~~filings~~filing in ~~September 2008 and~~ June 2010. ~~The~~On ~~2008~~August 8, 2011, ~~case~~the ~~covered~~NMPRC ~~PNM's~~issued ~~New~~a ~~Mexico~~final ~~retail~~order ~~customers~~modifying ~~except~~a ~~those~~stipulation ~~formerly~~reached ~~served~~ by ~~TNMP~~PNM ~~prior~~and toother ~~its~~parties ~~acquisition~~in bythis ~~PNMR (“PNM South”)~~case. ~~That~~The ~~case~~modified ~~was resolved in June 2009 with the NMPRC approving a~~ stipulation ~~resolving all issues, including~~provides:

• $77.1 million increase in annual non-fuel revenues, 65% of which was implemented July 1, 2009 and the remainder on April 1, 2010

• Inclusion of certain generation resources in determining rates that were previously operated on a merchant basis

• A more traditional FPPAC

Key components of PNM's 2010 Electric Rate Case application were:

• $165.2 million increase in annual non-fuel revenues, to be effective April 1, 2011

• Separate rate increases for customers of PNM South and other customers of PNM (“PNM North”)

• Future test period ending December 31, 2011

• FPPAC for PNM South

On August 8, 2011, the NMPRC issued a final order modifying a stipulation reached by PNM and other parties. The modified stipulation provides:


•	$72.1 million increase in annual non-fuel revenues for all New Mexico retail customers, implemented August 21, 2011

• Customers formerly served by TNMP prior to its acquisition by PNMR (“PNM South”) ~~customers~~ being covered by the same FPPAC utilized for other retail customers of PNM (“PNM North”)


•	Subject to further NMPRC approvals, recovery of costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning no earlier than August 2012


•	No new general rate adjustment effective prior to July 1, 2013, unless PNM needs to file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010


•	Limit on annual recovery of costs for fuel, renewable energy, and energy efficiency, with recovery of additional amounts deferred for collection to future periods

As permitted by the above NMPRC order, PNM filed an application in January 2012 for a rate rider to collect costs for renewable energy procurements incurred after December 31, 2010 that are not otherwise being collected in rates. These costs include the procurement of solar RECs from customers, wind resource procurements, and the revenue requirements for PNM-owned solar PV facilities and a solar battery storage demonstration project that went into service during 2011. On August 14, 2012, the NMPRC issued an order approving the rider. PNM implemented the rider on August 20, 2012. The rider will terminate upon a final order in PNM's next general rate case unless that order authorizes a continuation of the rider. Amounts that can be collected under the rider are capped at $18.0 million in 2012 and $24.6 million in 2013. Any amounts above the caps are deferred for future recovery without carrying costs. Collections under the rider during 2012 were below the cap. As a separate component of the rider, if PNM's earned return on jurisdictional equity in 2013, adjusted for weather and other items not representative of normal operation, exceeds 10.5%, it will refund to customers during May through December 2014 the amount over 10.5%.

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Table of Contents

•PNM Nohas ~~new~~entered ~~general~~into ~~rate~~firm-requirements ~~adjustment~~wholesale ~~prior~~contracts to ~~July~~provide 1,electricity ~~2013,~~to ~~unless~~various ~~PNM~~customers. These ~~needs~~contracts tocontain ~~file~~both capacity charges and energy charges. Capacity charges are monthly payments for ~~recovery~~a commitment of resources to service the contract requirements. Energy charges are payments based on the amount of electricity delivered to the customer and are intended to compensate for the variable costs incurred to ~~comply~~provide ~~with~~the ~~any~~energy. PNM's ~~federal~~firm-requirements ordemand ~~state~~was ~~environmental~~109 ~~law~~MW orin ~~requirement~~2012, ~~effective~~and ~~after~~is ~~June~~expected, 30based solely on existing contracts, ~~2010~~to be 106 MW in 2013, 106 MW in 2014, and 108 MW in 2015. No firm-requirements customer of PNM accounted for more than 2.5% of PNM's revenues for the year ended December 31, 2012.

•In ~~Limit~~September on2011, ~~annual~~PNM filed with FERC to increase rates for electric service and ancillary services provided to NEC, PNM's largest firm-requirements wholesale customer. PNM also requested a traditional FPPAC and full recovery of ~~costs~~certain third-party transmission charges. FERC issued an order allowing the increased rates to be collected beginning April 14, 2012, subject to refund. The parties agreed to a settlement providing for ~~fuel~~an increase in rates of $5.3 million, ~~renewable~~an ~~energy~~extension of the contract for 10 years, and an agreement that PNM will be able to file an application for formula based rates to be effective in 2015. The settlement has been filed with FERC and is pending FERC approval. PNM is unable to predict the outcome of this proceeding. PNM provides both energy ~~efficiency~~and power services to the City of Gallup, ~~with~~New ~~recovery~~Mexico, its second largest firm-requirements wholesale customer, under an electric service agreement that expires June 30, 2013. PNM and the City of ~~additional~~Gallup ~~amounts~~are ~~deferred~~in ~~for~~discussions ~~collection~~regarding PNM continuing to ~~future~~provide ~~periods~~services after the current agreement expires.

~~PNM~~In ~~Electric~~October ~~has~~2010, ~~entered~~PNM ~~into~~filed ~~firm-requirements~~a ~~wholesale~~notice ~~contracts~~with FERC to ~~provide~~increase ~~electricity~~its towholesale ~~various~~electric ~~customers. These~~transmission ~~contracts~~rates ~~contain~~for ~~both~~all ~~fixed~~of ~~capacity~~PNM's ~~charges~~wholesale ~~and~~electric ~~energy~~transmission ~~charges. Capacity~~service ~~charges~~customers, ~~are~~which ~~fixed~~include ~~monthly~~other ~~payments~~utilities, ~~for~~electric acooperatives, ~~commitment~~and ofentities ~~resources~~that use PNM's transmission system to ~~service~~transmit power at the ~~contract~~wholesale ~~requirements~~level. ~~Energy~~ The ~~charges~~proposed ~~are~~rates ~~payments~~were ~~based~~implemented on ~~the~~June 1, ~~amount~~2011, ofsubject ~~electricity~~to ~~delivered~~refund. On toJanuary ~~the~~2, ~~customer~~2013, ~~and~~FERC ~~are~~approved ~~intended~~a tosettlement ~~compensate~~among the parties providing for ~~the~~an ~~variable~~increase ~~costs~~in ~~incurred~~transmission toservice ~~provide~~revenues ~~the~~of ~~energy~~$2.9 million annually. PNM ~~Electric's~~refunded ~~firm-requirements~~amounts ~~demand~~collected ~~was~~in 96excess MWof the settled rates in ~~2011~~January 2013. In addition, ~~and~~the isparties ~~expected,~~agreed ~~based~~that ~~solely~~if onPNM ~~existing~~files ~~contracts,~~for toa beformula ~~103~~based MWrate inchange ~~2012,~~within ~~106~~one MWyear infrom ~~2013~~FERC's approval of the settlement agreement, ~~and~~no ~~113~~party MWwill inoppose ~~2014. No~~the ~~firm-requirements~~general ~~customer~~principle of ~~PNM~~a ~~Electric~~formula ~~accounted~~rate, ~~for~~although ~~more~~the ~~than~~parties ~~2.0%~~may ofstill ~~the~~object ~~PNM~~to ~~Electric's~~particular ~~revenues~~aspects ~~for~~of the ~~year~~formula. The ~~ended~~rate ~~December~~increase ~~31,~~does ~~2011~~not impact PNM's retail customers.

In ~~September~~December ~~2011~~2012, PNM filed a notice with FERC to increase ~~rates~~its bywholesale ~~$8.7~~electric ~~million~~transmission ~~or 39.8% over existing~~ rates for ~~electric~~all ~~service and ancillary services provided to NEC, one~~ of ~~PNM's~~its ~~firm-requirement~~transmission ~~wholesale~~ customers. ~~PNM~~The ~~also~~proposed ~~requests~~increase ais ~~traditional FPPAC and full recovery of certain third-party transmission charges~~$3. ~~NEC~~2 ~~challenged~~million ~~PNM's~~annually ~~filing~~and ~~with~~is ~~FERC.~~a Onformula ~~November~~based ~~14,~~rate ~~2011,~~as ~~FERC~~contemplated ~~issued~~by ~~an order accepting~~ the ~~agreement~~approved assettlement ~~filed~~in ~~and allowing~~ the ~~increased~~case ~~rates~~described toabove. FERC behas ~~collected~~not ~~beginning~~taken ~~April~~action ~~14,~~on ~~2012,~~the ~~subject~~filing toand ~~refund. The parties are currently in settlement negotiations.~~ PNM is unable to predict the outcome of this proceeding.

In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually, based on a return on equity of 12.25%. If approved, the rate increase would apply to all of PNM's wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM's transmission system to transmit power at the wholesale level. The proposed rate increase would not impact PNM's retail customers. The proposed rates were implemented on June 1, 2011, subject to refund. PNM and other parties to the case had engaged in settlement discussions. A hearing for this proceeding is scheduled to commence on April 4, 2012. Subsequent to the scheduling of the hearing, the staff of FERC made a filing recommending an annual revenue increase of $4.6 million, based on a return on equity of 10.4%. After the FERC staff made its filing, settlement discussions have resumed and are ongoing. PNM is unable to predict the outcome of this proceeding.

Operational Information

Weather-normalized retail electric loads ~~increased~~decreased by 10.47% in ~~2011~~2012. The system peak demands for retail and firm-requirements customers were:

System Peak Demands

	2011	2010		2009
	2012		2011		2010
	(Megawatts)
Summer	1,~~938~~948	~~1,973~~	1,938	~~1,866~~	1,973
Winter	1,~~709~~523	~~1,551~~	1,709	~~1,531~~	1,551

PNM holds long-term, non-exclusive franchise agreements for its electric retail operations, with varying expiration dates. These franchise agreements allow the utility to access public rights-of-way for placement of its electric facilities. Franchise agreements have expired in some areas PNM serves, including Albuquerque, Rio Rancho, and Santa Fe. Because PNM remains obligated under New Mexico state law to provide service to customers in these areas, the expirations should not have a material adverse impact. The Albuquerque, Rio Rancho, and Santa Fe metropolitan areas accounted for 4648.35%, 1011.73%, and 9.25% of PNM ~~Electric~~'s ~~2011~~2012 revenues and no other franchise area represents more than 5%. Although PNM is not required to collect or pay franchise fees in some areas it serves, the utility continues to collect and pay such fees in certain parts of its service territory, including Albuquerque, Rio Rancho, and Santa Fe.

PNM ~~Electric~~ owns or leases 3,189 circuit miles of electric transmission lines that interconnect with other utilities in New Mexico, Arizona, Colorado, Texas, and Utah. Although there has been modest load growth in the utility's service territory in recent years, there has been little development of new transmission facilities. Therefore, most of the capacity on PNM's transmission system is fully committed during peak hours, with very little to no additional access available on a firm commitment basis. These factors result in physical constraints on the system and limit the ability to wheel power into PNM ~~Electric~~'s service area from outside of New Mexico.

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PNM ~~Electric~~ also generates and sells electricity into the wholesale market. Because PNM's 134 MW share of Unit 3 at PVNGS is ~~permanently~~ excluded from retail rates, that unit's power is being sold onin the wholesale market. In April 2008, PNM entered into three separate contracts for the sale of capacity and energy related to its entire interest in PVNGS Unit 3 through December 31, 2010. Subsequently, the utility ~~entered~~has ~~into~~sold ~~contracts to sell~~ its share of the unit output ~~through~~daily ~~December~~at ~~31,~~market ~~2011~~prices. ~~Because~~PNM ofhas ~~lower~~established ~~existing~~fixed ~~market~~rates ~~prices,~~for ~~margins~~all ~~associated~~of ~~with~~these sales through the ~~contracts~~end ~~for~~of ~~2011~~2013 ~~were~~through ~~significantly~~hedging ~~lower~~arrangements ~~than~~that ~~those~~are ~~achieved~~accounted infor ~~the~~as ~~2008~~economic ~~agreements~~hedges. PNM's ~~contracts~~is toalso ~~sell~~partially ~~portions~~hedged offor ~~the~~2014. Because ~~power~~of ~~from~~lower ~~PVNGS~~existing ~~Unit~~market 3prices, inmargins ~~2012~~associated ~~and~~with ~~2013~~sales ~~also~~subsequent ~~reflect~~to ~~lower~~2010 ~~market~~were ~~prices. The~~significantly ~~unit's~~lower ~~remaining~~than ~~power~~those isachieved ~~sold~~ in the ~~spot~~2008 ~~market~~agreements. Beyond the PVNGS contracts, PNM ~~Electric~~ also engages in activities to optimize its existing jurisdictional assets and long-term purchase power agreements through spot market, hour ahead, day ahead, week ahead, and other sales of any excess generation not required to fulfill retail load and contractual commitments. Revenues from these sales, other than those from PVNGS Unit 3, are credited to retail customers through the FPPAC.

Use of Future Test Year

Senate Bill 477 (“SB 477”) was passed by the New Mexico legislature and became effective in June 2009. SB 477 is designed to promote more timely recovery of reasonable costs of providing utility service in two ways.


•	The NMPRC must set rates using the test period that best reflects the conditions the utility will experience when new rates are anticipated to go into effect. The NMPRC is required to consider that a future test period may be the one that best meets this requirement. A future test period is a twelve-month period beginning no later than the date a proposed rate change is expected to take effect.


•	The NMPRC must include certain construction work in progress (“CWIP”) for environmental improvement, generation, and transmission projects in rate base, without an offset for AFUDC. With this provision, PNM will be able to collect costs as projects are being built rather than waiting until they are finished to include them in rate base.

The use of a future test year should help PNM mitigate the adverse effects of regulatory lag, which is inherent when using a historical test year. Accordingly, the utility's earnings should more closely reflect the rate of return allowed by the NMPRC. PNMR believes that achieving earnings that approximate its allowed rate of return is an important factor in attracting equity investors, as well as being considered favorably by credit rating agencies and financial analysts. In November 2012, the NMPRC issued an order promulgating rules that clarify the filing requirements for public utility rate applications based on a future test year.

PNM previously announced it anticipated filing a request for a general rate increase with the NMPRC in mid-2013. With the uncertainty related to environmental capital spending described in Note 16 and improved operating results, PNM is re-evaluating when it will file its next general rate case. As with any forward looking financial information, utilizing a future test year in a rate filing presents challenges that exist in the forecasting process. These include forecasts of both operating and capital expenditures that necessitate reliance on many assumptions concerning future conditions and operating results. In the rate making process, PNM's assumptions are subject to challenge by regulators and intervenors who may assert different interpretations or assumptions. ~~The settlement reached in PNM's 2010 Electric Rate Case reflected some aspects of a future test year.~~

Renewable Portfolio Standard

The REA was enacted to encourage the development of renewable energy in New Mexico. The act establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to ~~5% of retail electric sales by January 1, 2006, increasing to~~ 10% by 2011, 15% by 2015, and 20% by 2020. The 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. PNM files required renewable energy plans with the NMPRC annually. See Note 17.

TNMP ~~Electric~~

TNMP ~~Electric~~ is a regulated utility operating in Texas. TNMP's predecessor was organized in 1925. TNMP is incorporated in the State of Texas.

TNMP ~~Electric~~ provides transmission and distribution services in Texas under the provisions of TECA and the Texas Public Utility Regulatory Act. TNMP is subject to traditional cost-of-service regulation with respect to rates and service under the jurisdiction of the PUCT and certain municipalities. Because its transmission and distribution activities are solely within ERCOT, TNMP is not subject to traditional rate regulation by FERC. TNMP ~~Electric~~ serves a market of small to medium sized communities, most of which ~~have populations of less than 50,000. TNMP is the exclusive provider of transmission and distribution services in most areas it serves.~~

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~~TNMP~~have ~~Electric's~~populations ~~service territory consists~~ of ~~three~~less ~~non-contiguous~~than ~~areas~~50,000. ~~One~~TNMP ~~portion of this territory extends from Lewisville, which~~ is ~~approximately 10 miles north of~~ the ~~Dallas-Fort~~exclusive ~~Worth~~provider ~~International Airport, eastward to municipalities near the Red River, and to communities north, west and south~~ of ~~Fort~~transmission ~~Worth. The second portion of its service territory includes the area along the Texas Gulf Coast between Houston~~ and ~~Galveston,~~distribution ~~and~~services ~~the~~in ~~third~~most ~~portion includes~~ areas ofit ~~far west Texas between Midland and El Paso~~serves. ~~ERCOT is the independent system operator that is responsible for maintaining reliable operations for the bulk electric power supply system in its region.~~

TNMP's ~~Electric~~service ~~provides~~territory ~~transmission~~consists ~~and~~of ~~distribution~~three ~~services~~non-contiguous atareas. One ~~regulated~~portion ~~rates~~of tothis ~~various~~territory ~~REPs~~extends ~~that~~from Lewisville, inwhich ~~turn,~~is ~~provide~~approximately ~~retail~~10 ~~electric~~miles ~~service~~north toof ~~consumers~~the ~~within~~Dallas-Fort ~~TNMP~~Worth ~~Electric's~~International ~~service~~Airport, ~~area. As~~eastward ofto ~~December~~municipalities ~~31,~~near ~~2011~~the Red River, 83and ~~active~~to ~~REPs~~communities ~~receive~~north, ~~transmission~~west, and ~~distribution~~south ~~services~~of ~~from~~Fort ~~TNMP Electric~~Worth. ~~First~~The ~~Choice~~second ~~was~~portion ~~TNMP~~of ~~Electric's~~its ~~second~~service ~~largest~~territory ~~customer~~includes ~~and~~the ~~accounted~~area ~~for~~along ~~17%~~the ofTexas ~~TNMP's~~Gulf ~~revenues~~Coast ~~for~~between ~~the~~Houston ~~year~~and ~~ended~~Galveston, ~~December~~and ~~31,~~the ~~2011. Revenues~~third ofportion ~~other~~includes ~~large~~areas ~~customers~~of ~~accounted~~far ~~for~~west ~~19%~~Texas ~~and~~between ~~12%~~Midland ofand ~~TNMP's~~El ~~revenues~~Paso. No ERCOT ~~other~~is ~~customers~~the ~~accounted~~independent system operator that is responsible for ~~more~~maintaining ~~than~~reliable ~~10%~~operations offor ~~revenues~~the bulk electric power supply system in its region.

TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP's service area. As of December 31, 2012, 89 active REPs receive transmission and distribution services from TNMP. The acquirer of First Choice, including the former First Choice operations, accounted for 19% of TNMP's revenues in 2012. Two other unaffiliated customers of TNMP accounted for operating revenues of 17% in 2012 and 10% in 2012. No other customer accounted for more than 10% of revenues.

Regulatory Activities

In ~~June~~August ~~2009~~2010, TNMP ~~and~~filed ~~other~~with ~~parties~~the ~~reached~~PUCT afor ~~unanimous settlement resolving all issues in~~ a general rate ~~case~~increase. On ~~filed~~January in27, ~~2008. The~~2011, the PUCT approved ~~the~~a ~~settlement~~stipulation inthat ~~August~~settles ~~2009~~the case. ~~Highlights~~Key components of the settlement ~~included~~were:

• $12.7 million annual increase in revenues, reflecting interest and other costs associated with debt refinancing in March 2009

• Adjustment of the interest rate TNMP is allowed to collect on its CTC to reflect debt refinancing costs

• Recovery of Hurricane Ike restoration costs plus carrying costs over five years

The PUCT approved an interim adjustment to TNMP's transmission rates of $5.5 million on May 14, 2010.

On August 26, 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues. On January 27, 2011, the PUCT approved a stipulation that settles the case. Key components of the settlement were:


•	A revenue increase of $10.25 million, effective February 1, 2011


•	A return on equity of 10.125%


•	A hypothetical 55%/45% debt-equity capital structure

The PUCT approved interim adjustments to TNMP's transmission rates of $5.5 million on May 14, 2010 and $2.5 million on September 27, 2012.

Franchise Agreements

TNMP holds long-term, non-exclusive franchise agreements for its electric transmission and distribution services. These agreements have varying expiration dates and some have expired. TNMP intends to negotiate and execute new or amended franchise agreements with municipalities where the agreements have expired or will be expiring. Since TNMP ~~Electric~~ is the exclusive provider of transmission and distribution services in most areas that it serves, the need to renew or renegotiate franchise agreements should not have a material adverse impact on TNMP's business. TNMP also earns revenues from service provided to facilities in its service area that lie outside the territorial jurisdiction of the municipalities with which TNMP has franchise agreements.

PNM Gas

On January 30, 2009, PNM completed the sale of its PNM Gas segment (Note 2) for $620.0 million in cash, plus a working capital adjustment. PNM recognized an after-tax gain of $65.3 million. PNM used the after-tax proceeds from the sale to retire short-term debt and pay a dividend of $220.0 million to PNMR. Financial information regarding PNM's gas operations, which are reflected as discontinued operations, is presented in Note 22. PNM Gas distributed natural gas to most of the large communities in New Mexico under rates that were subject to traditional rate regulation by the NMPRC. PNM Gas had a customer base that included both sales-service customers and transportation-service customers.

Competitive Businesses

First Choice

As discussed in Note 23, PNMR completed the sale of First Choice on November 1, 2011 receiving $270.0 million, plus $59.3 million for estimated working capital. The latter amount iswas subject to adjustment based on the actual amounts of certain components of working capital at October 31, 2011. PNMR recognized a pre-tax gain of $174.9 million on the sale in 2011. The ~~purchaser~~parties ~~has~~could ~~informed~~not ~~PNMR~~agree ~~that~~on itthe ~~believes~~ working capital atamount ~~October~~and, 31in accordance with the agreement for the sale, ~~2011~~this matter was ~~overstated~~submitted byto an independent party for a decision binding on the parties. A decision was received in August 2012 resulting in an additional pre-tax gain of $41.20 million in 2012. PNMR ~~has~~used ~~responded~~the net proceeds from the sale of First Choice to repurchase some of PNMR's outstanding debt and equity and for other corporate purposes, including repayment of borrowings under the PNMR Revolving Credit Facility.

First Choice, operating as a certified REP in ERCOT, provided electricity to residential, small commercial and governmental customers. First Choice focused its competitive customer acquisition efforts in major Texas metropolitan areas open to electric choice within ERCOT, including Dallas-Fort Worth, Houston, Corpus Christi, and McAllen-Harlingen. Although First Choice was regulated in certain respects by the PUCT, its business was not subject to traditional rate of return regulation. Rates were negotiated by First Choice with each customer. No specific provisions existed for the recovery of First Choice's purchased power costs and changes in those costs affected operating results.

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tobase, ~~the~~which ~~purchaser~~along ~~disputing~~with the ~~purchaser's~~impacts ~~calculation~~of Hurricane Ike and ~~indicating~~depressed ~~that~~economic ~~working~~conditions ~~capital~~resulted atin ~~October~~significant ~~31,~~increases ~~2011~~in ~~was~~the ~~understated~~levels byof ~~$6.5~~uncollectible ~~million. PNMR~~accounts ~~believes~~and ~~its~~bad ~~calculation~~debt isexpense. First ~~consistent~~Choice's ~~with~~load ~~the~~fluctuated ~~terms~~due ofto ~~the~~customer ~~agreement. PNMR~~additions ~~does~~and ~~not~~losses, ~~believe~~changes ~~the~~in ~~ultimate~~customer ~~resolution~~usage, and seasonality of ~~this~~weather. First ~~matter~~Choice ~~will~~experienced ~~have~~increased asales ~~material~~and ~~impact. PNMR~~operating ~~used~~revenues during the ~~net~~summer ~~proceeds~~months ~~from~~as ~~the~~a ~~sale~~result of ~~First~~increased ~~Choice~~air toconditioner ~~repurchase~~usage. First ~~some~~Choice ofmonitored ~~PNMR's~~and ~~outstanding~~revised ~~debt~~its ~~and~~load ~~equity~~forecast ~~and~~to account for ~~other~~changing ~~corporate~~customer ~~purposes,~~loads ~~including~~and ~~repayment~~entered ofinto ~~borrowings~~hedging ~~under~~arrangements ~~the~~to ~~PNMR~~cover ~~Revolving~~forecasted ~~Credit Facility~~sales.

First Choice, operating as a certified REP in ERCOT, provided electricity to residential, small commercial and governmental customers. First Choice focused its competitive customer acquisition efforts in the major Texas metropolitan areas that are open to electric choice within ERCOT, including Dallas-Fort Worth, Houston, Corpus Christi, and McAllen-Harlingen. Although First Choice was regulated in certain respects by the PUCT, its business was not subject to traditional rate of return regulation. Rates were negotiated by First Choice with each customer, rather than being regulated by the PUCT. Because the Texas electricity market is deregulated, no specific provisions existed for the recovery of First Choice's fuel and purchased power costs. As a result, purchased power costs affected First Choice's operating results.

During the period it was a subsidiary of PNMR, First Choice's operating results were pressured by several factors. Due to the competitive nature of the Texas market, First Choice, similar to other REPs, experienced significant turnover in its customer base. Since the provision of Texas regulation that requires customers to pay their previous REP before obtaining service from another REP is limited, numerous customers left First Choice with bills still outstanding. In addition, the impacts of Hurricane Ike and depressed economic conditions resulted in significant increases in the levels of uncollectible accounts and bad debt expense. First Choice's load fluctuated due to customer additions and losses, changes in customer usage, and seasonality of weather. First Choice experienced increased sales and operating revenues during the summer months as a result of increased air conditioner usage in hot weather. First Choice monitored and revised its load forecast to account for changing customer loads and entered into hedging arrangements to cover forecasted sales.

Optim Energy

In January 2007, PNMR and ECJV, a wholly owned subsidiary of Cascade, which until late in 2011 was a large PNMR shareholder, created Optim Energy to serve expanding ~~U.S.~~ energy markets, principally the areas of Texas covered by ERCOT. Optim Energy's business consisted of development, operation, and ownership of diverse generation assets, complemented by wholesale marketing to optimize those assets. ~~ECJV is a wholly owned subsidiary of Cascade, which until late in 2011 was a large~~ PNMR ~~shareholder. PNMR~~ and ECJV each had a 50 percent ownership interest in Optim Energy, a limited liability company. Optim Energy had interests in three electric generating resources located within the ERCOT area.

Beginning in 2009, Optim Energy was affected by continuing adverse market conditions, primarily low natural gas and power prices. In response to those adverse conditions, Optim Energy changed its strategy to focus on utilizing cash flow from operations to reduce debt. Optim Energy also concentrated on optimizing generation assets as a stand-alone independent power producer.

As discussed in Note 21, PNMR determined its investment in Optim Energy was fully impaired at December 31, 2010 and reduced the carrying value of the investment to zero by recording a pre-tax loss of $188.2 million. PNMR, ECJV, and Cascade entered into agreements on September 23, 2011, whereby Optim Energy was restructured and ECJV made an equity contribution to Optim Energy in exchange for an increased ownership interest, which resulted in PNMR's ownership in Optim Energy being reduced from 50% to 1%. On January 4, 2012, ECJV exercised its option to acquire PNMR's remaining 1% ownership interest in Optim Energy at fair market value, which was determined to be zero. PNMR accounted for its investment in Optim Energy using the equity method of accounting through September 23, 2011 and used the cost method thereafter. In accordance with GAAP, PNMR did not record income or losses associated with its investment in Optim Energy in 2011.

Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. PNMR Services Company provides corporate services through shared services agreements to PNMR and all of PNMR's business units, including PNM and TNMP, and through transition services agreements with First Choice and Optim Energy. These services are charged and billed on a monthly basis to the business units. Billings are at cost, except for services provided to Optim Energy, which ~~includes~~included a profit element.

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SOURCES OF POWER

PNMR

First Choice bought electricity and entered into hedging arrangements to purchase quantities of power to match the supply obligations to customers that are under fixed price contracts. Power was purchased long-term in the over-the-counter market or using futures. In the short term, hedges were adjusted to load changes by buying and selling power in the over-the-counter market or ERCOT day-ahead market.

PNM

Generation Capacity

As of December 31, ~~2011~~2012, the total net generation capacity of facilities owned or leased by PNM was 2,~~347~~333 MW. PNM also obtains ~~200~~204 MW of power under a long-term PPA with the New Mexico Wind Energy Center.

~~PNM's~~A- ~~owned and leased capacity in electric generating facilities in commercial service as of December 31, 2011 is:~~6

			Generation
			Capacity
Type	Name	Location	(MW)
Coal	SJGS	Waterflow, New Mexico	790
Coal	Four Corners	Fruitland, New Mexico	202
Gas/Oil	Reeves Station	Albuquerque, New Mexico	154
Gas	Afton (combined cycle)	La Mesa, New Mexico	235
Gas	Lordsburg	Lordsburg, New Mexico	80
Gas	Luna (combined cycle)	Deming, New Mexico	185
Gas/Oil	Delta	Albuquerque, New Mexico	132
Gas	Valencia	Belen, New Mexico	145
Nuclear	PVNGS	Wintersburg, Arizona	402
Solar	PNM-owned solar	Five sites in New Mexico	22
			2,347

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PNM's owned and leased capacity in electric generating facilities in commercial service as of December 31, 2012 is:



			Generation
			Capacity
Type	Name	Location	(MW)
Coal	SJGS	Waterflow, New Mexico	783
Coal	Four Corners	Fruitland, New Mexico	200
Gas	Reeves Station	Albuquerque, New Mexico	154
Gas	Afton (combined cycle)	La Mesa, New Mexico	230
Gas	Lordsburg	Lordsburg, New Mexico	80
Gas	Luna (combined cycle)	Deming, New Mexico	185
Gas/Oil	Delta	Albuquerque, New Mexico	132
Gas	Valencia	Belen, New Mexico	145
Nuclear	PVNGS	Wintersburg, Arizona	402
Solar	PNM-owned solar	Five sites in New Mexico	22
			2,333

Fossil‑Fueled Plants

SJGS consists of four units operated by PNM. Units 1, 2, 3, and 4 at SJGS have net rated capacities of 340 MW, 340 MW, ~~498~~496 MW and ~~523~~507 MW. SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson. SJGS Unit 3 is owned 50% by PNM, 41.8% by SCPPA, and 8.2% by Tri‑State. SJGS Unit 4 is owned 38.457% by PNM, 28.8% by MSR Public Power Agency, 10.04% by the City of Anaheim, California, 8.475% by the City of Farmington, New Mexico, 7.2% by the County of Los Alamos, New Mexico, and 7.028% by UAMPS. See Note 16 for additional information about SJGS.

Four Corners Units 4 and 5 are 13% owned by PNM. Units 4 and 5 at Four Corners are jointly owned with SCE, APS, SRP, Tucson, and EPE and are operated by APS. PNM has no ownership interest in Four Corners Units 1, 2, or 3. Four Corners and a portion of the facilities adjacent to SJGS are located on land held under easements from the United States and also under leases from the Navajo Nation. APS, on behalf of the Four Corners participants, has negotiated amendments to an existing facility lease with the Navajo Nation that would extend the leasehold interest in the plant to 2041. The amendments have been approved by the Navajo Nation Council and signed by the Nation's President. DOI must also approve the amendments as well as a related federal rights-of-way grant that the Four Corners participants will pursue. A federal environmental review will be conducted as part of the DOI review process. See Note 16 for additional information about Four Corners.

PNM owns 100% of Reeves, Afton, and Lordsburg and 33.3% of Luna. The remaining interests in Luna are owned equally by Tucson and Freeport McMoran. PNM is entitled to the energy and capacity of Delta under a PPA that is deemed to be an operating lease. PNM has a PPA that entitles it to the entire output of Valencia. Valencia is a variable interest entity and is consolidated by PNM as required by GAAP. Therefore, Valencia is reflected in the above table as if it were owned. Reeves, Lordsburg, Delta, and Valencia are used primarily for peaking power and transmission support. ~~Lordsburg,~~See ~~Luna,~~Note ~~and~~9 ~~Valencia~~for ~~became~~additional ~~included~~information inabout ~~retail rates under~~ the ~~2008~~Delta ~~Electric~~operating ~~Rate~~lease, ~~Case. See~~including ~~Note~~the 9potential ~~and~~purchase ~~Note~~of 17Delta.

Nuclear Plant

PNM is participating in the three units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), Salt River Project, EPE, SCE, SCPPA, and the Department of Water and Power of the City of Los Angeles. PNM is entitled to 10.2% of the power and energy generated by PVNGS. PNM has ownership interests of 2.3% in Unit 1, 4.6% in Unit 2, and 10.2% in Unit 3 and has leasehold interests of 7.9% in Unit 1 and 5.6% in Unit 2. The lease payments for the leased portions of PVNGS are recovered through retail rates approved by the NMPRC. See Note 7 for additional information concerning the PVNGS leases, including notices given to the lessors under the PVNGS Unit 1 leases in 2013 that PNM would renew the leases. See Note 16 for information on other PVNGS matters.

On March 11, 2011, a 9.0 magnitude earthquake occurred off the northeastern coast of Japan. The earthquake produced tsunamis that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Following these events, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. In March 2012, the NRC issued the first regulatory requirements based on the recommendations of the task force. With respect to PVNGS, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of

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~~Nuclear~~power ~~Plant~~at plants; and (2) enhancement of spent fuel pool instrumentation. The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Due to the developing nature of these requirements, APS and PNM cannot predict the financial or operational impacts on PVNGS; however PVNGS continues to comply with regulatory requirements and related reporting.

The lease payments for the leased portions of PVNGS are recovered through retail rates approved by the NMPRC. In July 2009, PNM acquired the ownership of a portion of PVNGS Unit 2 previously owned by another PNMR subsidiary and leased to PNM. This asset is included in rates charged to retail customers.

As part of recent refueling outages, PVNGS installed new reactor vessel closure heads and simplified head assembly modifications. These projects are designed to provide safety benefits, eliminate costly inspections, and reduce the duration of future outages.

On March 11, 2011, a 9.0 magnitude earthquake occurred off the northeastern coast of Japan. The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Following these events, the NRC commissioners launched a two-pronged review of U.S. nuclear power plant safety. The NRC supported the establishment of an agency task force to conduct both a near- and long-term analysis of the lessons that can be learned from the situation in Japan. The near-term task force issued a report on July 12, 2011, and on October 3, 2011, the NRC staff issued a plan for implementing the near-term task force's recommendations. On October 18, 2011, the NRC commissioners directed the NRC staff to implement, without delay, the near-term task force recommendations, subject to certain conditions. One such condition is that the agency should strive to complete and implement lessons learned from the earthquake and tsunami in Japan within five years. A second condition is that the staff should designate the recommendation for a rulemaking to address extended loss of offsite power to be completed within 24 to 30 months. PNM cannot predict when or if the NRC will take formal action as a result of its review.

Solar

In 2011, PNM completed its first major utility-owned renewable energy project when five utility-scale solar facilities in New Mexico went online. The five solar sites are located in Alamogordo, Deming, Los Lunas, Las Vegas, and Albuquerque. In addition to these facilities, PNM completed its solar-storage demonstration project in Albuquerque, which has a generation capacity of 0.5 MW that is not included in the above table. The NMPRC has approved PNM's 2013 renewable energy procurement strategy that includes an additional 21.5 MW of utility-owned solar capacity.

Plant Operating Statistics

Equivalent availability of PNM's major base-load generating stations were:

Plant	Operator	~~2011~~2012	~~2010~~2011	~~2009~~2010
SJGS	PNM	8681.97%	7386.59%	8473.95%
Four Corners	APS	8183.5%	7581.35%	8775.53%
PVNGS	APS	8990.16%	8889.61%	8788.06%

Joint Projects

SJGS, PVNGS, ~~and~~ Four Corners, and Luna are joint projects each owned or leased by several different utilities. Some participants in the joint projects are investor-owned utilities, while others are municipally or co-operatively owned. Furthermore, participants in SJGS and Four Corners may have varying percentage interests in different generating units within the project. The primary operating or participation agreements for the joint projects expire in 2016 for Four Corners, 2022 for SJGS, and 2027 for PVNGS. In addition, SJGS and Four Corners are coal-fired generating plants that obtain their coal requirements from mines near the plants. The agreements for coal supply expire in 2016 for Four Corners and 2017 for SJGS. As described above, Four Corners is situated on land under a lease from the Navajo Nation. Portions of PNM's interests in PVNGS Units 1 and 2 are through leases that expire in 2015 and 2016, but contain certain fixed-rate renewal and fair market value purchase options. As (discussed in Note 7), PNM gave notice to the lessors in 2013 that PNM would renew the PVNGS Unit 1 leases and would retain control of the assets subject to the PVNGS Unit 2 leases at the expiration of the leases. Several of the participants in the joint projects are located in California. There are legislative and regulatory mandates in California that prohibit utilities from entering into new, or extending existing, arrangements for coal-fired generation. It is also possible that the participants in the joint projects have changed circumstances and objectives from those existing at the time of becoming participants. The status of these joint projects is further complicated by the uncertainty surrounding the form of potential legislation and/or regulation of GHG, CCBs, and other air emissions, as well as the impacts of the costs of compliance and operational viability of all or certain units within the joint projects. It is unclear how these factors will enter into discussion and negotiations concerning the status of the joint projects as the expiration of basic operational agreements approaches. PNM can provide no assurance that its participation in the joint projects will continue in the manner that currently exists. See Note 16.

PPAs

In addition to generating its own power, PNM purchases power under long-term PPAs. PNM also purchases power in the forward, day-ahead, and real-time markets.

In 2002, PNM entered into an agreement with FPL to develop the New Mexico Wind Energy Center. PNM began receiving power from the project in June 2003. FPL owns and operates the New Mexico Wind Energy Center, which consists of 136 wind-powered turbines on a site in eastern New Mexico. PNM has a contract to purchase all the power and RECs generated by the New Mexico Wind Energy Center for 25 years. The NMPRC has approved a voluntary tariff that allows PNM retail customers to buy wind-generated electricity for a small monthly premium. Power from the New Mexico Wind Energy Center is used to service load under the voluntary tariff and as part of PNM's electric supply mix for meeting retail load.

PNM's 2013 renewable energy procurement plan includes a 20-year agreement to purchase energy from a geothermal facility to be built near Lordsburg. The 10 MW facility will be the first geothermal project for the PNM system and is scheduled to be completed by December 31, 2013.

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GHG, CCBs, and other air emissions, as well as the impacts of the costs of compliance and operational viability of all or certain units within the joint projects. It is unclear how these factors will enter into discussion and negotiations concerning the status of the joint projects as the expiration of basic operational agreements approaches. PNM can provide no assurance that its participation in the joint projects will continue in the manner that currently exists.

PPAs

In addition to generating its own power, PNM Electric purchases power under long-term PPAs. PNM also purchases power in the forward, day-ahead, and real-time markets.

In 2002, PNM entered into an agreement with FPL to develop a 200 MW wind generation facility in New Mexico. PNM began receiving power from the project in June 2003. FPL owns and operates the New Mexico Wind Energy Center, which consists of 136 wind-powered turbines on a site in eastern New Mexico. PNM has a contract to purchase all the power and RECs generated by the New Mexico Wind Energy Center for 25 years. In 2003, PNM received approval from the NMPRC for a voluntary tariff that allows PNM retail customers to buy wind-generated electricity for a small monthly premium. Power from the New Mexico Wind Energy Center is used to service load under the voluntary tariff and as part of PNM's electric supply mix for meeting retail load.

A summary of purchased power, excluding Delta and Valencia, but including power purchased under long-term contracts that have expired by their terms, is as follows:

	Year Ended December 31,
	2011		2010		2009
	2012		2011		2010
Purchased under long-term PPAs
MWh	~~794~~546,~~867~~321		1794,~~360,991~~867		1,~~533~~360,~~643~~991
Cost per MWh	$	2927.9325	$	3429.3693	$	3134.3736
Other purchased power
Total MWh	~~988~~948,~~564~~911		1988,~~083,548~~564		1,083,~~272~~548
Cost per MWh	$	3127.4730	$	4031.6147	$	3740.4261

TNMP

TNMP provides only transmission and distribution services and does not sell power.

First Choice

First Choice bought electricity and entered into hedging arrangements to purchase quantities of power to match the supply obligations to customers that were under fixed price contracts. Power was purchased long-term in the over-the-counter market or using futures. In the short term, hedges were adjusted to load changes by buying and selling power in the over-the-counter market or ERCOT day-ahead market.

FUEL AND WATER SUPPLY

PNM

The percentages of PNM’'s generation of electricity (on the basis of KWh), ~~excluding~~including Valencia and Delta, fueled by coal, nuclear fuel, and gas and oil, and the average costs to PNM of those fuels per MMBTU were as follows:

	Coal				Nuclear				Gas and Oil
	Percent ofGeneration		AverageCost		Percent ofGeneration		AverageCost		Percent ofGeneration		AverageCost
2011	62.4	%	$	2.79	30.0	%	$	0.80	7.4	%	$	4.42
2012	59.2	%	$	2.99	31.3	%	$	0.88	9.0	%	$	3.25
2010	59.4	%	$	2.49	31.5	%	$	0.66	9.1	%	$	4.53
2011	61.8	%	$	2.79	29.7	%	$	0.80	8.4	%	$	4.47
2009	61.3	%	$	2.25	27.6	%	$	0.56	11.1	%	$	3.52
2010	58.9	%	$	2.49	31.3	%	$	0.66	9.8	%	$	4.54

In 2012 and 2011, 0.25% and 0.1% of PNM's generation was from utility owned solar, which has no fuel cost. The generation mix for ~~2012~~2013 is expected to be 6260.42% coal, 2928.25% nuclear, 710.98% gas and oil, and 0.5% utility owned solar. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits, and the generally adequate supply of nuclear fuel, PNM believes that adequate sources of fuel are available for its generating stations into the foreseeable future. See Sources of Power - PNM - PPAs for information concerning the cost of purchased power.

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Coal

The coal supply contracts that provide fuel for SJGS and Four Corners expire in 2017 and 2016. Coal supply has not been arranged for periods after the existing contracts expire. PNM believes there is adequate availability of coal resources to continue to operate these plants although extended or new contracts could result in higher prices. See Note 16 for additional information about PNM's coal supply.

Natural Gas

The natural gas used as fuel for the electric generating plants is procured on the open market and delivered by third party transportation providers.

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Nuclear Fuel and Waste

PNM is one of several participants in PVNGS. The PVNGS participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The PVNGS participants have contracted ~~95%~~for all of PVNGS's requirements for uranium concentrates through ~~2015~~2016, 9095% of its requirements for ~~2016-~~2017, and 80% of its requirements for 2018. The participants have contracted for all of PVNGS's conversion services through ~~2015~~2016, 90% of its requirements in 2017, and 95% of its requirements ~~through~~in 2018. All of PVNGS's enrichment services are contracted through 2020 and all of PVNGS's fuel assembly fabrication services through 2016.

~~The~~In ~~Nuclear~~August ~~Waste~~2012, ~~Policy~~one ~~Act~~ of ~~1982~~PVNGS's ~~required~~suppliers ~~the~~that ~~DOE~~converts touranium ~~begin~~concentrates to ~~accept,~~uranium ~~transport,~~hexafluoride ~~and~~invoked ~~dispose~~the offorce ~~spent~~majeure ~~nuclear~~provision ~~fuel~~in ~~and~~its ~~high~~contract ~~level~~when ~~waste~~it ~~generated~~shut bydown ~~the~~its ~~nation's~~conversion ~~nuclear~~plant ~~power~~due ~~plants~~to byregulatory ~~1998~~compliance issues. The ~~DOE~~PVNGS ~~failed~~participants tohave ~~begin~~sufficient ~~accepting~~strategic ~~PVNGS's~~reserves ~~spent~~of ~~nuclear~~enriched ~~fuel~~uranium bysuch ~~1998,~~that ~~and~~they ~~APS~~do ~~(on~~not ~~behalf~~anticipate ofa ~~itself~~short ~~and~~term ~~the~~impact ~~other~~on ~~PVNGS~~nuclear ~~participants)~~fuel ~~filed~~supplies as a ~~lawsuit~~result ~~for~~of ~~DOE's~~the ~~breach~~force inmajeure ~~the U~~declaration.S. The ~~Court~~uranium ofconversion ~~Federal~~supplier ~~Claims. The~~has ~~Court~~undertaken ofthe ~~Federal~~necessary ~~Claims~~upgrades ~~ruled~~to inits ~~favor~~facility ofto ~~APS~~address the regulatory compliance issues and anticipates resuming operations in ~~October~~a ~~2010~~time ~~awarded~~frame ~~$30.2~~that ~~million~~will not result in ~~damages~~an toadverse ~~the~~impact on PVNGS's ~~participants~~ability ~~for~~to ~~costs~~secure ~~incurred~~long-term ~~through~~conversion ~~December 2006~~services. ~~See~~However, ~~Note~~the 16participants are continuing to evaluate alternate long-term options for securing conversion services.

The ~~DOE~~Nuclear ~~had~~Waste ~~planned~~Policy toAct ~~meet~~of ~~its~~1982 ~~disposal~~required ~~obligations~~the byDOE ~~designing,~~to ~~licensing~~begin to accept, ~~constructing~~transport, and ~~operating~~dispose aof ~~permanent~~spent ~~geologic~~nuclear ~~repository~~fuel atand ~~Yucca~~high ~~Mountain,~~level ~~Nevada~~waste generated by the nation's nuclear power plants by 1998. InThe ~~June~~DOE ~~2008,~~failed ~~DOE~~to ~~submitted~~begin ~~its~~accepting ~~application~~spent tonuclear ~~the~~fuel ~~NRC~~by to1998, ~~authorize~~and ~~construction~~APS (on behalf of itself and the ~~Yucca~~other ~~Mountain~~PVNGS ~~repository. In~~participants) ~~March~~filed ~~2010,~~a ~~the~~lawsuit for DOE's ~~filed~~breach ain ~~motion~~the toUnited ~~dismiss~~States ~~with~~Court ~~prejudice~~of ~~its~~Federal ~~Yucca~~Claims. The ~~Mountain~~Court ~~construction~~of ~~authorization~~Federal ~~application~~Claims ~~that~~ruled ~~was~~in ~~pending~~favor ~~before~~of ~~the~~APS ~~NRC. Several~~and ~~interested~~in ~~parties~~October ~~have~~2010 ~~intervened~~awarded $30.2 million in damages to the ~~NRC~~PVNGS ~~proceeding,~~participants ~~but~~for ~~the~~costs ~~matter~~incurred ~~has~~through ~~not~~December ~~been~~2006. APS ~~conclusively~~filed ~~decided~~a bysubsequent ~~either~~lawsuit ~~the~~against ~~NRC~~DOE orin the ~~courts~~Court of Federal Claims on December 19, 2012. ~~Additionally,~~The alawsuit ~~number~~alleges ofthat ~~interested~~from ~~parties~~January ~~have~~1, ~~filed~~2007, athrough ~~variety~~June of30, ~~lawsuits~~2011, inAPS, ~~different~~as ~~jurisdictions~~a ~~around~~co-owner ~~the~~of ~~country~~PVNGS, ~~challenging~~incurred ~~the~~additional ~~DOE's~~damages ~~authority~~due to ~~withdraw~~DOE's ~~the~~continuing ~~Yucca~~failure ~~Mountain~~to ~~construction~~remove ~~authorization~~spent ~~application. None~~nuclear offuel ~~these~~and ~~lawsuits~~high ~~has~~level ~~been~~waste ~~conclusively~~from ~~decided~~PVNGS. See byNote ~~the courts~~16.

OnThe ~~January~~DOE 26had planned to meet its disposal obligations by designing, ~~2012~~licensing, ~~the~~constructing, ~~Blue~~and ~~Ribbon~~operating ~~Commission~~a onpermanent ~~America's~~geologic ~~Nuclear~~repository ~~Future~~at (Yucca Mountain, Nevada. In March 2010, the ~~“Blue~~DOE ~~Ribbon~~filed ~~Commission”)~~a ~~made~~motion ~~recommendations~~to ondismiss ~~managing~~with ~~the~~prejudice ~~back~~its ~~end~~Yucca ofMountain ~~the~~construction ~~nuclear~~authorization ~~fuel~~application ~~cycle~~that was pending before the NRC. ~~The~~Several ~~Blue~~interested ~~Ribbon~~parties ~~Commission~~have ~~was~~intervened ~~established~~ in ~~early~~the ~~2010~~NRC atproceeding, but the ~~direction~~matter ofhas ~~President~~not ~~Obama~~been conclusively decided by either the NRC or the courts. ~~The~~Additionally, ~~President's~~a ~~directive~~number ~~was~~of ~~based~~interested onparties ~~his~~have ~~assessment~~filed ~~that~~a ~~the~~variety ~~nation's~~of ~~approach~~lawsuits toin ~~managing~~different ~~used~~jurisdictions ~~nuclear~~around ~~fuel,~~the ~~primarily~~country ~~through~~challenging the ~~repository~~DOE's atauthority to withdraw the Yucca Mountain, construction authorization application. None of these lawsuits has ~~proven~~been toconclusively bedecided ~~ineffective~~by the courts.

The Blue Ribbon Commission's report recommended a strategy with several key elements including: a new consent-based approach to siting future nuclear waste management facilities; a new organization dedicated solely to implementing the waste management program; access to the funds nuclear utility ratepayers are providing for the purpose of nuclear waste management; prompt efforts to develop geologic disposal facilities, consolidated storage facilities and to prepare for the eventual large-scale transport of spent nuclear fuel and high-level waste to consolidated storage and disposal facilities. PNM and APS are monitoring this matter, but cannot predict the proposed timing for implementation of the recommended strategy.

All spent nuclear fuel from PVNGS is being stored on-site. PVNGS has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license periods, which end in November 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the extended license periods, which end in November 2047. If uncertainties regarding the United States government's obligation to accept and store spent fuel are not favorably resolved, the PVNGS participants will evaluate alternative storage solutions. These may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the extended license periods.

In addition to the spent fuel stored at PVNGS's on-site ISFSI, PVNGS also generates certain types of low level radioactive waste that are stored on-site. Currently, the higher radioactivity of the low level wastes is stored on-site since industry access to a disposal site was eliminated several years ago. The NRC is considering regulations that would allow the industry to eliminate

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much of this waste by blending it with lower level waste so that it can be disposed of at a facility such as the one PVNGS utilizes in Utah.

Water Supply

See Note 16 for information about PNM's water supply.

ENVIRONMENTAL MATTERS

Electric utilities are subject to stringent laws and regulations for protection of the environment by local, state, federal, and tribal authorities. In addition, PVNGS is subject to the jurisdiction of the NRC, which has the authority to issue permits and licenses and to regulate nuclear facilities in order to protect the health and safety of the public from radioactive hazards and to conduct environmental reviews pursuant to the National Environmental Policy Act. The liabilities under these laws and regulations can be material. In some instances, liabilities may be imposed without regard to fault, or may be imposed for past acts, whether or not such acts were lawful at the time they occurred. The construction expenditure projection includes environmental upgrades at Four Corners, but does not include any amounts related to environmental upgrades at SJGS ~~or Four Corners~~ that may be required by EPA to address regional haze described in Note 16 ~~or any other significant expenditures for environmental control facilities~~. See MD&A - Other Issues Facing the Company - Climate Change Issues for information ~~on GHG. In addition, Note 16 contains information related to the following matters, incorporated in this item by reference:~~

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on GHG. In addition, Note 16 contains information related to the following matters, incorporated in this item by reference:


•	PVNGS Decommissioning Funding


•	Nuclear Spent Fuel and Waste Disposal


•	Environmental Matters under the caption “The Clean Air Act”


•	Endangered Species Act


•	Cooling Water Intake Structures


•	Santa Fe Generating Station

• Environmental Matters under the caption “Coal Combustion Byproducts Waste Disposal”


•	Hazardous Air Pollutants (“HAPs”) Rulemaking

COMPETITION

Regulated utilities are generally not subject to competition from other utilities in areas that are under the jurisdiction of state regulatory commissions. In New Mexico, PNM does not have competition for services provided to its retail electric customers. In Texas, TNMP is not currently in any direct retail competition with any other regulated electric utility. However, PNM and TNMP are subject to customer conservation activities and initiatives to utilize alternative energy sources or otherwise bypass the PNM and TNMP systems.

PNM is subject to varying degrees of competition in certain territories adjacent to or within the areas it serves. This competition comes from other utilities in its region as well as rural electric cooperatives and municipal utilities. PNM is involved in the generation and sale of electricity into the wholesale market. It is subject to competition from regional utilities with similar opportunities to generate and sell energy at market-based prices and larger trading entities that do not own or operate generating assets.

EMPLOYEES

The following table sets forth the number of employees of PNMR, PNM, and TNMP as of December 31, ~~2011~~2012:

	PNMR	PNM	TNMP
Corporate (1)	~~492~~461	—	—
PNM Electric	1,117	1,117	—
PNM	1,091	1,091	—
TNMP Electric	342	—	342
TNMP	357	—	357
Total	1,~~951~~909	1,~~117~~091	~~342~~357

(1)Represents employees of PNMR Services Company.

As of December 31, ~~2011~~2012, PNM ~~Electric~~ had ~~635~~592 employees in its power plant and operations areas that are currently covered by a collective bargaining agreement with the IBEW that was entered into in ~~May~~July ~~2009~~2012 and expires April 30, ~~2012~~2015. PNMR has no other employees represented by unions. Negotiations for a new agreement with the IBEW began in February 2012. While the Company is optimistic that a timely agreement will be reached, PNM cannot, at this time, predict the outcome of the negotiations.

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PNM has completed contingency planning for certain scenarios that may occur as a result of negotiations. In the negotiations, PNM is focusing its efforts towards meeting four objectives: improved safety, continued compliance, continued reliability, and cost management. The wages and benefits for all PNM employees who are members of the IBEW are typically included in the rates charged to electric customers, subject to approval of the NMPRC.

DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

Statements made in this filing that relate to future events or PNMR's, PNM's, or TNMP's expectations, projections, estimates, intentions, goals, targets, and strategies are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that all forward-looking statements are based upon current expectations and estimates. PNMR, PNM, and TNMP assume no obligation to update this information.

Because actual results may differ materially from those expressed or implied by these forward-looking statements, PNMR, PNM, and TNMP caution readers not to place undue reliance on these statements. PNMR's, PNM's, and TNMP's business, financial condition, cash flow, and operating results are influenced by many factors, which are often beyond their control, that can cause actual results to differ from those expressed or implied by the forward-looking statements. These factors include:


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


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

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

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

•compliance ~~The~~and ~~risk~~other ~~that~~impacts ~~recently~~on ~~enacted~~the ~~reliability~~operations ~~standards~~and ~~regarding~~economic ~~available~~viability ~~transmission capacity may negatively impact the operation~~ of PNM's ~~transmission~~generating ~~system~~plants

• The ~~performance~~risk ofthat ~~generating~~recently ~~units,~~enacted ~~transmission~~reliability ~~systems,~~standards ~~and~~regarding ~~distribution~~available ~~systems,~~transmission ~~which~~capacity ~~could~~and beother ~~negatively affected by a number of significant operational issues~~FERC

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rulemakings may negatively impact the operation of PNM's transmission system


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


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

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

• ~~Uncertainties~~Uncertainty surrounding the ~~mine~~status ~~fire~~of ~~incident~~PNM's atparticipation in jointly-owned generation projects resulting from the ~~mine~~scheduled ~~supplying~~expiration ~~coal~~of tothe ~~SJGS~~operational agreements for the projects

• 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


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


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


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


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


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


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

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

• ~~The~~Commodity ~~effectiveness~~and ofcounterparty credit risk ~~management~~transactions and ~~commodity~~the effectiveness of risk ~~transactions~~management


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


•	Changes in applicable accounting principles

For information about the risks associated with the use of derivative financial instruments see Part II, Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”

SECURITIES ACT DISCLAIMER

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

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ITEM 1A. RISK FACTORS

The business and financial results of PNMR, PNM, and TNMP are subject to a number of risks and uncertainties, including those set forth below and in MD&A, Note 16, and Note 17. TNMP provides transmission and distribution services to REPs that provide electric service to consumers in TNMP's service territories. References to customers in the risk factors discussed below also encompass the customers of these REPs who are the ultimate consumers of electricity transmitted and distributed through TNMP's facilities.

Regulatory Factors

The profitability of PNMR's utilities depends on being able to recover their costs through regulated rates and earn a fair return on invested capital.

The rates PNM charges its customers are regulated by the NMPRC and FERC. TNMP is regulated by the PUCT. ~~Under~~The ~~its~~Company ~~current~~is ~~rate~~in ~~settlement,~~a ~~PNM~~period ~~cannot~~requiring ~~request~~significant acapital ~~general~~investment ~~rate~~and ~~increase~~is ~~for~~projecting ~~its~~total ~~New~~construction ~~Mexico~~expenditures ~~customers~~for ~~that~~the ~~would~~years be2013-2017 ~~effective prior~~ to ~~July~~be $1,781.9 ~~2013~~million. See Note 14. The Company anticipates a trend toward increasing costs, for which it ~~might~~will have to seek regulatory recovery. These include or are related to:

• ~~New~~Environmental ~~asset~~compliance ~~construction related to the provision of electric service~~expenditures

• ~~Potential~~New ~~environmental~~asset ~~compliance~~construction ~~expenditures~~related to generation, transmission, and distribution systems necessary to provide electric service


•	The regulatory mandate to generate power from renewable resources

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•	Increased regulation related to nuclear safety


•	Fuel costs

• Costs related to ~~rights-of-way,~~ pension and ~~benefit expenses~~benefits

• ~~Depreciation~~Increased ~~expenses~~interest costs to finance capital investments

~~Without~~• ~~timely cost recovery and the authorization to earn a reasonable return on invested capital, the Company's liquidity and results of operations could be negatively impacted.~~ Depreciation

At the same time the Company's costs are increasing, there are factors placing downward pressures on the demand for power, thereby reducing load growth in the Company's service territories. These include:


•	Adverse economic conditions


•	Reductions in costs of energy efficiency technology


•	Unpredictable weather patterns


•	Reduced new sources of demand


•	Changing customer behaviors

The combination of costs increasing relatively rapidly and the slowing of customer demand places upward pressure on the per unit prices that must be charged by the Company to recover its costs. This upward pressure on unit prices results in additional efforts by customers to reduce consumption. Without timely cost recovery and the authorization to earn a reasonable return on invested capital, the Company's liquidity and results of operations could be negatively impacted.

Under New Mexico law, utilities may propose the use of a future test year in establishing rates. As with any forward looking financial information, a future test year presents challenges that are inherent in the forecasting process. Forecasts of both operating and capital expenditures necessitate reliance on many assumptions concerning future conditions and operating results. Accordingly, if PNM chooses to request rates based on a future test year, but cannot successfully support it, cash flows and results of operations may be negatively impacted. This could result from not being able to withstand challenges from regulators and intervenors regarding the utility's capability to make reasonable forecasts.

PNM recovers the cost of fuel for its generation facilities through its FPPAC. The coal supply contracts that provide fuel for SJGS and Four Corners expire in 2017 and 2016. Coal supply has not been arranged for periods after the existing contracts expire. It is possible that extended contracts with the existing suppliers or new contracts for coal from alternative sources could result in higher prices. Although PNM believes such costs would continue to be recovered through the FPPAC, there can be no assurance that full recovery would continue to be allowed.

PNMR's utilities are subject to numerous federal, state, and local environmental laws and regulations that may significantly limit or affect their operations and financial results.

Compliance with federal, state, and local environmental laws and regulations, including those addressing climate change, air quality, CCBs, discharges of wastewater and streams originating from fly ash and bottom ash handling facilities, cooling water, and other matters, may result in increased capital, operating, and other costs. These costs could include remediation, containment, civil liability, and monitoring expenses. PNMR, PNM, and TNMP cannot predict how they would be affected if existing environmental laws and regulations were to be revised or reinterpreted, or if new environmental statutes and rules were to be adopted. See Note 16.

~~Recently,~~ EPA has issued its ~~proposed~~ BART determinations for both SJGS and Four Corners under the program to address regional haze in the “four corners” area., Ifwhich would reduce the ~~proposals~~levels ~~are~~of ~~finalized~~NOx inemitted ~~the~~at ~~form~~both ~~issued,~~plants. Significant capital expenditures would be required for the ~~levels~~installation of ~~NOx~~SCR ~~emitted~~technology at both ~~SJGS~~generating stations and ~~Four~~operating ~~Corners~~costs would ~~have to be reduced~~increase. ~~This~~On ~~would~~February ~~require~~15, ~~significant~~2013, ~~capital~~PNM, ~~expenditures~~NMED, and ~~increased~~EPA ~~operating~~agreed ~~costs~~to ~~for~~pursue ~~the~~a ~~installation~~revised ofplan ~~SCR~~regarding ~~technology~~SJGS, atwhich ~~both~~is ~~generating~~discussed ~~stations~~in Note 16.

EPA, environmental advocacy groups, other organizations, and some other federal and state agencies are predicted to focus considerable attention to GHG from power generation facilities, including their role in climate change. PNM depends on fossil-fueled generation for a significant share of its electricity. Therefore, it could be exposed to possible future GHG regulations imposed by New Mexico and/or the federal government. Any such regulations could result in additional operating restrictions on facilities and increased generation and compliance costs.

CCBs from the operation of SJGS are currently being used in the reclamation of a surface coal mine. These CCBs consist of fly ash, bottom ash, and gypsum. Any new regulation that would affect the reclamation process, including CCBs being classified as hazardous waste by EPA, could significantly increase the costs of the disposal of CCBs.

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~~CCBs~~A ~~from~~regulatory ~~the~~body ~~operation~~may ofidentify ~~SJGS~~a ~~are~~site ~~currently~~requiring ~~being~~environmental ~~used~~cleanup inand ~~the~~designate ~~reclamation~~PNM ofor aTNMP ~~surface~~as ~~coal~~a ~~mine~~responsible party. ~~These~~There ~~CCBs~~is ~~consist~~also ofuncertainty ~~fly~~in ~~ash,~~quantifying ~~bottom~~exposure ~~ash,~~under environmental laws that impose joint and ~~gypsum~~several liability on all potentially responsible parties. ~~Any~~Failure ~~new~~to ~~regulation~~comply ~~that~~with ~~would~~environmental ~~affect~~laws ~~the~~and ~~reclamation process~~regulations, ~~including~~even ~~CCBs~~if ~~being~~caused ~~classified~~by asfactors ~~hazardous~~beyond ~~waste~~PNM's byor ~~EPA~~TNMP's control, ~~could~~may ~~significantly~~result ~~increase~~in the ~~costs~~assessment of ~~the~~civil ~~disposal~~or ofcriminal ~~CCBs~~penalties and fines.

APNMR ~~regulatory~~and ~~body~~its operating subsidiaries may ~~identify~~underestimate athe ~~site~~costs ~~requiring~~of environmental ~~cleanup~~compliance, liabilities, and ~~designate~~litigation ~~PNM~~due orto ~~TNMP~~the asuncertainty acurrently ~~reasonable~~inherent ~~party~~in these factors. ~~There~~Although there is ~~also~~ uncertainty inabout ~~quantifying~~the ~~exposure~~timing ~~under~~and ~~environmental~~form ~~laws~~of ~~that~~regulations ~~impose~~regarding ~~joint~~climate change, CCBs, and ~~several~~other ~~liability~~power onplant ~~all~~emissions, ~~potentially~~such ~~responsible~~regulations ~~parties~~could have a material impact on operations. ~~Failure~~It is possible that requirements to comply with ~~environmental~~the ~~laws~~final ~~and~~BART ~~regulations~~determinations, ~~even~~combined ifwith ~~caused~~the byfinancial ~~factors~~impact ~~beyond~~of ~~PNM's~~possible future climate change regulation or ~~TNMP's~~legislation, ~~control~~if any, ~~may~~other environmental regulations, the result inof litigation, the ~~assessment~~adequacy and timeliness of ~~civil~~cost recovery mechanisms, and other business considerations, could jeopardize the economic viability of Four Corners and/or ~~criminal~~SJGS ~~penalties~~or the ability of individual participants to continue participation in those plants. Timely regulatory recovery of costs associated with any environmental-related regulations would be needed to maintain a strong financial and ~~fines~~operational profile. The above factors could adversely affect the Company's business, financial position, results of operations, and liquidity.

PNMR ~~and its operating subsidiaries may underestimate the costs of environmental compliance~~, ~~liabilities~~PNM, and ~~litigation~~TNMP ~~due~~are subject to ~~the~~complex ~~uncertainty~~government ~~currently~~regulation ~~inherent~~unrelated into ~~these factors. Although there is uncertainty about~~ the ~~timing and form of regulations regarding climate change~~environment, ~~CCBs,~~which ~~and~~may ~~other power plant emissions, such regulations could~~ have a ~~material~~negative impact on ~~operations. It~~their 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, the adequacy and timeliness of cost recovery mechanisms, and other business considerations, could jeopardize the economic viability of SJGS and/or Four Corners or the ability of individual participants to continue participation in those plants. Timely regulatory recovery of costs associated with any environmental-related regulations would be needed to maintain a strong financial and operational profile. The above factors could adversely affect the Company's businesses, financial position, and results of operations~~, and liquidity~~.

To operate their businesses, PNMR, PNM, and TNMP are ~~subject~~required to ~~complex~~have ~~government~~numerous ~~regulation,~~permits ~~which~~and ~~may~~approvals ~~have~~from a ~~negative~~variety ~~impact~~of onregulatory ~~their~~agencies. Regulatory ~~businesses~~bodies with jurisdiction over the utilities include the NMPRC, ~~financial~~NMED, ~~position~~PUCT, TCEQ, ERCOT, FERC, NRC, EPA, and ~~results~~NERC. Oversight by these agencies cover many aspects of the Company`s utility operations including: siting, construction, and operation of facilities; the purchase of power under long-term contracts; conditions of service; the issuance of securities; and rates charged to customers.

ToFERC ~~operate~~has ~~their~~issued ~~businesses,~~a ~~PNMR,~~number ~~PNM,~~of ~~and~~rules ~~TNMP~~pertaining ~~are required~~ to ~~have~~preventing ~~numerous~~undue ~~permits~~discrimination ~~and~~in ~~approvals~~transmission ~~from~~services aand ~~variety~~electric ofreliability ~~regulatory agencies~~standards. ~~Regulatory~~A ~~bodies~~rule ~~with~~issued ~~jurisdiction~~in ~~over~~2011 revised the ~~utilities~~determination ~~include~~of ~~the~~total ~~NMPRC,~~transmission ~~NMED,~~capability ~~PUCT,~~under ~~TCEQ,~~the ~~ERCOT,~~reliability ~~FERC,~~standards ~~NRC,~~for ~~EPA,~~transmission ~~and NERC~~systems. ~~Oversight~~The byorder ~~these~~could ~~agencies~~potentially ~~cover~~reduce ~~many~~the ~~aspects~~total oftransmission ~~the~~capacity ~~Company`s~~that ~~utility~~we ~~operations. These~~use ~~include:~~to ~~siting,~~deliver ~~construction,~~our ~~and~~generation ~~operation~~resources ofto ~~facilities;~~customers. Such ~~the~~reductions ~~purchase~~could ofrequire ~~power~~us ~~under~~to ~~long-term~~acquire ~~contracts;~~additional ~~conditions~~transmission ofrights ~~service;~~or ~~the~~assets, ~~issuance~~which ofcould ~~securities;~~involve substantial investments and ~~rates~~a ~~charged~~significant amount of time to ~~customers~~accomplish.

FERC has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards. In one of these, issued in 2011, FERC revised the determination of total transmission capability under the reliability standards for transmission systems. The order could potentially reduce the total transmission capacity that we use to deliver our generation resources to customers. Such reductions could require us to acquire additional transmission rights or assets, which could involve substantial investments and a significant amount of time to accomplish.

PNMR and its subsidiaries are unable to predict the impact on their business and operating results from future actions of any agency regulating us. Changes in existing regulations or the adoption of new ones could result in additional expenses and/or changes in our business operations. In turn, operating results could be adversely impacted.

Operational Factors

The financial performance of PNMR, PNM, and TNMP may be adversely affected if power plants and transmission and distribution systems do not operate reliably and efficiently.

Our financial performance depends on the successful operation of PNM's generation assets, as well as the transmission and distribution systems of PNM and TNMP. Unscheduled or longer than expected maintenance outages, breakdown or failure of equipment or processes due to aging infrastructure, other performance problems with the electric generation assets, severe weather conditions, accidents and other catastrophic events, acts of war or terrorism, disruptions in the supply and delivery of fuel, and other factors could result in PNM's load requirements being larger than available system generation capacity. In addition, unplanned outages of generating units and extensions of scheduled outages occur from time to time and are an inherent risk of the Company's business. If ~~this~~these were to occur, PNM would be required to purchase electricity in either the wholesale market or spot market at the then-current market price. There can be no assurance that sufficient electricity would be available at reasonable prices, or available at all. The failure of transmission or distribution facilities may also affect PNM`s and TNMP`s ability to deliver power. These potential generation, distribution, and transmission problems, and any service interruptions related to them, could result in lost revenues and additional costs.

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

The Company functions in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure, some of which are deemed to be critical infrastructure under NERC guidelines. Certain of the Company's systems are interconnected with external networks. In the regular course of business, the utilities handle a range of sensitive security and customer information. PNM and TNMP are subject to different agencies' laws and rules concerning safeguarding and maintaining the confidentiality of this information.

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In the event a party desires to disrupt the bulk power or transmission systems in the United States, the Company's computer systems could be subject to cyber attack. Despite implementation of security measures, the technology systems are vulnerable to disability, failures, or unauthorized access. A successful cyber attack or other similar failure of the systems could impact the reliability of PNM's generation and PNM's and TNMP's transmission and distribution systems, including the possible unauthorized shutdown of our facilities. Such an event could lead to significant disruptions of business operations, including the Company's ability to serve and bill customers and to process other financial information. A major cyber incident could lead to increased regulatory oversight, litigation, fines, other remedial action, and reputational damage. The costs incurred to investigate and remediate a cyber security attack could be significant. If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised. A security breach of the Company's information systems could have a material adverse impact on the operations and financial condition of PNMR, PNM, and TNMP.

Customer electricity usage could be reduced by increases in prices we charge and other factors. This could result in underutilization of PNM's generating capacity, as well as the capacities of PNM's and TNMP's transmission and distribution systems. Should this occur, operating and capital costs might not be fully recovered, and financial performance thus negatively impacted.

Many factors influence customers' electricity purchases. These include, but are not limited to:

• ~~Increases~~Rates ~~in rates~~ charged by PNM and TNMP


•	Rates charged by REPs utilizing TNMP's facilities to deliver power


•	Availability and cost of alternative sources of power


•	National, regional, or local economic conditions

These factors and others may prompt customers to institute energy efficiency measures or take other actions that would result in lower power consumption. If customers bypass or underutilize our facilities through self-generation, through renewable or other energy resources, technological change, or other measures, our revenues would be negatively impacted.

PNM's and TNMP's service territories include several military bases and federally funded national laboratories, as well as large industrial customers that have significant direct and indirect impacts on the local economies where they operate. We do not directly provide service to any of the military bases or national laboratories, but do provide service to large industrial customers. Our business could be hurt from the impacts on the local economies associated with these customer groups, as well as directly from the large industrial customers, for a number of reasons, including:


•	Federally-mandated base closures or significant curtailment of the activities at the bases or national laboratories


•	Closure of industrial facilities or significant curtailment of their activities

Another factor that could negatively impact us is that initiatives are periodically undertaken in various localities to municipalize or otherwise take over Company facilities. If any such municipalization initiative is successful, the result could be a material reduction in the usage of our facilities.

Should any of the above factors result in our facilities being underutilized, our financial position, operational results, and cash flows could be significantly impacted.

Demand for power could exceed supply capacity, resulting in increased costs for purchasing capacity in the open market or building additional generation facilities.

PNM is obligated to supply power to retail customers and certain wholesale customers. At peak times, power demand could exceed PNM's available generation capacity. Market or competitive forces may require PNM to purchase capacity on the open market or build additional generation capabilities. Regulators or market conditions may not permit PNM to pass all of these purchases or construction costs on to their customers. If that occurs, PNM may not be able to recover these costs fully. Or, there may be a lag between when costs are incurred and when regulators permit recovery in customers' rates. These situations could have negative impacts on results of operations and cash flows.

There are inherent risks in the ownership and operation of nuclear facilities.

PNM has a 10.2% undivided interest in PVNGS, representing 17.12% of PNM's total owned and leased generating capacity. Portions of the interests in Units 1 and 2 are held under leases. PVNGS is subject to environmental, health, and financial risks, ~~including, but not limited to:~~

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including, but not limited to:


•	The ability to obtain adequate supplies of nuclear fuel and water


•	The ability to dispose of spent nuclear fuel


•	Decommissioning of the plant


•	Securing the facilities against possible terrorist attacks


•	Unscheduled outages due to equipment failures

PNM maintains trust funds designed to provide adequate financial resources for decommissioning at the end of the expected life of the PVNGS units. However, if the units are decommissioned before their planned date, these funds may prove to be insufficient. PNM also has external insurance coverage to minimize its financial exposure to some risks. However, it is possible that liabilities associated with nuclear operations could exceed the amount of insurance coverage. See Note 16.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority, depending upon the NRC's assessment of the severity of the situation, to impose monetary civil penalties or a progressively increased inspection regime. This could ultimately result in the shutdown of a unit, the removal of a unit from service until compliance is achieved, or both. Increased costs resulting from penalties, a heightened level of scrutiny, and/or implementation of plans to achieve compliance with NRC requirements could adversely affect the financial condition, results of operations, and cash flows of PNMR and PNM.

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of the severity of the situation, to impose monetary civil penalties or a progressively increased inspection regime. This could ultimately result in the shutdown of a unit, the removal of a unit from service until compliance is achieved, or both. Increased costs resulting from penalties, a heightened level of scrutiny, and/or implementation of plans to achieve compliance with NRC requirements could adversely affect the financial condition, results of operations, and cash flows of PNMR and PNM.

The PVNGS participants have no reason to anticipate a serious nuclear incident at PVNGS. However, if an incident did occur, it could materially and adversely affect the results of operations and financial condition of PNM and PNMR. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. For example, as a result of the March 2011 earthquake and tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, there may be additional regulations or other changes that would affect PVNGS.

Costs of decommissioning, remediation, and restoration of nuclear and fossil-fueled power plants, as well as related coal mines, could exceed the estimates of PNMR and PNM, which could negatively impact results of operations and liquidity.

PNM has interests in a nuclear power plant, two coal-fired power plants, and several natural gas-fired power plants. PNM is obligated to pay for the costs of decommissioning its share of the power plants. PNM is also obligated to pay for its share of the costs of decommissioning the mines that supply coal to the coal-fired power plants. Rates charged by PNM to its customers, as approved by the NMPRC, include a provision for recovery of certain costs of decommissioning, remediation, and restoration. The NMPRC has established a cap on decommissioning costs for the surface coal mines. In the event any of these costs exceed current estimates and PNM is unsuccessful in recovering the expenses through increased rates, results of operations will be negatively impacted.

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

The Company functions in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. In the regular course of business, the utilities handle a range of sensitive security and customer information. PNM and TNMP are subject to different agencies' laws and rules concerning safeguarding and maintaining the confidentiality of this information. Despite implementation of security measures, the technology systems are vulnerable to disability, failures, or unauthorized access. Such failures or breaches of the systems could impact the reliability of PNM's generation and PNM's and TNMP's transmission and distribution systems, including the possible unauthorized shutdown of our facilities. If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised. A security breach of the Company's information systems could have a material adverse impact on the operations and financial condition of PNMR, PNM, and TNMP. Such a breach could involve theft or the inappropriate release of certain types of information, including confidential data related to customers or operating systems.

General Economic and Weather Factors

General economic conditions of the state, region, and nation can affect our customers and suppliers. Economic recession or downturn may result in decreased consumption and increased bad debt expense, and could also negatively impact our suppliers, all of which could negatively impact us.

Economic activity is a key factor in PNMR subsidiaries' performance. Decreased economic activity can lead to declines in energy consumption, which could adversely affect future revenues, earnings, and growth. Higher unemployment rates both in our service territories and nationwide could result in commercial customers ceasing operations and lower levels of income for our residential customers. These customers might then be unable to pay their bills on time, which could increase bad debt expense and negatively impact results of operations and cash flows. Economic conditions also impact the supply and/or cost of commodities and materials needed to construct or acquire utility assets or make necessary repairs.

The operating results of PNMR and its operating subsidiaries fluctuate on a seasonal and quarterly basis as well as being affected by weather conditions, including regional drought.

Electric generation, transmission, and distribution are generally seasonal businesses that vary with the demand for power. With power consumption typically peaking during the hot summer months, revenues traditionally peak during that period. As a result, quarterly operating results of PNMR and its operating subsidiaries vary throughout the year. In addition, PNMR and its operating subsidiaries have historically had less revenues resulting in earning less income when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net earnings, and cash flows of the companies.

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Drought conditions in New Mexico, especially in the “four corners” region, where SJGS and Four Corners are located, may affect the water supply for PNM's generating plants. If inadequate precipitation occurs in the watershed that supplies that region, PNM may have to decrease generation at these plants. This would require PNM to purchase power to serve customers and/or reduce the ability to sell excess power on the wholesale market and reduce revenues. Drought conditions or actions taken by regulators or legislators could limit PNM's supply of water, which would adversely impact PNM's and PNMR's business. Although PNM has in place supplemental contracts and voluntary shortage sharing agreements with tribes and other water users in the “four corners” region, PNM cannot be certain these contracts will be enforceable in the event of a major drought or that it will be able to renew these contracts in the future.

TNMP`s service areas are exposed to extreme weather, including high winds, drought, flooding, and periodic hurricanes. These severe weather events can physically damage TNMP's owned facilities. Such an occurrence both disrupts the ability to deliver energy and increases costs. Extreme weather can also reduce customers' usage and demand for energy. These factors could negatively impact results of operations and cash flows.

Financial Factors

Disruption in the credit and capital markets may impact our growth strategy and ability to raise capital.

PNMR and its subsidiaries rely on access to both short-term money markets and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations, including energy infrastructure investments and new projects. In general, the Company relies on its short-term credit facilities as the initial source to finance construction expenditures. This results in increased borrowings under the facilities over time. The Company is currently projecting total construction expenditures for the years ~~2012~~2013-~~2016~~2017 to be $1,~~306~~781.9 million. If PNMR or its operating subsidiaries are not able to access capital at competitive rates, or at all, PNMR's ability to finance capital requirements and implement its strategy will be limited. Disruptions in the credit markets, which could negatively impact our access to capital, could be caused by:


•	An economic recession


•	Declines in the health of the banking sector generally, and the failure of specific banks who are parties to our credit facilities


•	The bankruptcy of an unrelated energy company

• ~~Terrorist~~War, terrorist attacks or threatened attacks ~~on facilities of PNMR's operating subsidiaries~~


•	Deterioration in the overall health of the utility industry

If our cash flow and credit and capital resources are insufficient to fund our capital expenditure plans, we may be forced to delay important capital investments, sell assets, seek additional equity or debt capital, or restructure our debt. In addition, insufficient cash flows and capital resources may result in reductions of our credit ratings. This could harm our ability to incur additional indebtedness on acceptable terms and would result in an increase in the interest rates applicable under our credit facilities. Our cash flow and capital resources may be insufficient to pay interest and principal on our debt in the future. If that should occur, our capital raising or debt restructuring measures may be unsuccessful or inadequate to meet our scheduled debt service obligations. This could cause us to default on our obligations and further impair our liquidity.

Future reduction in our credit ratings or changing rating agency requirements could materially and adversely affect our growth, strategy, business, financial position, results of operations, and liquidity.

PNMR, PNM, and TNMP cannot be sure that any of their current ratings will remain in effect for any given period of time or that a rating will not be put under review for a downgrade, lowered, or withdrawn entirely by a rating agency. Downgrades or changing requirements could result in increased borrowing costs due to higher interest rates in future financings, a smaller potential pool of investors, and decreased funding sources. It also could require the provision of additional support in the form of letters of credit and cash or other collateral to various counterparties.

PNMR may be unable to meet its ongoing and future financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay dividends or distributions to PNMR.

PNMR is a holding company and has no operations of its own. PNMR's ability to meet its financial obligations and to pay dividends on its common stock primarily depends on the net income and cash flows of PNM and TNMP and their capacity to pay upstream dividends or distributions. Prior to providing funds to PNMR, PNM and TNMP have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of PNM, preferred stock dividends.

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The NMPRC has placed certain restrictions on the ability of PNM to pay dividends to PNMR, including that PNM cannot pay dividends that cause its debt rating to fall below investment grade. The NMPRC has also restricted PNM from paying dividends in any year, as determined on a rolling four-quarter basis, in excess of net earnings without prior NMPRC approval. PNM is permitted to pay dividends to PNMR from prior equity contributions made by PNMR. Additionally, PNM has various financial covenants that limit the transfer of assets, through dividends or other means.

Further, the ability of PNMR to declare dividends depends upon:


•	The extent to which cash flows will support dividends


•	The Company's financial circumstances and performance


•	NMPRC's and PUCT's decisions in various regulatory cases currently pending and which may be docketed in the future


•	Conditions imposed by the NMPRC or PUCT


•	The effect of federal regulatory decisions and legislative acts


•	Economic conditions in the United States


•	Future growth plans and the related capital requirements


•	Other business considerations

Impairments of ~~intangible~~goodwill and long-lived assets of PNMR, PNM, and TNMP could adversely affect ~~their~~the Company's business, financial position, liquidity, and results of operations.

PNMR, PNM, and TNMP annually evaluate their ~~intangible~~recorded ~~long-lived assets, including~~ goodwill, for impairment. They also assess ~~tangible and intangible~~ long-lived assets whenever indicators of impairment exist. Factors that affect the long-term value of these assets as well as other economic and market conditions could result in impairments. Significant impairments could adversely affect our business, financial position, liquidity, and results of operations.

Declines in values of marketable securities held in trust funds for pension and other postretirement benefits and in the NDT could result in sustained increases in costs and funding requirements for those obligations, which may affect operational results.

The Company targets 4231% of its pension trust funds and 70% of its trust funds for other postretirement benefits to be invested in marketable equity securities. Over one-half of funds held in the NDT are typically invested in marketable equity securities. Declines in market values could result in increased funding of the trusts as well as the recognition of losses as impairments for the NDT and additional expense for the benefit plans.

PNM's PVNGS leases describe certain events, including “Events of Loss” and “Deemed Loss Events”, the occurrence of which could require PNM to take ownership of the underlying assets and pay the lessors for the assets.

The “Events of Loss” generally relate to casualties, accidents, and other events at PVNGS, including the occurrence of specified nuclear events, which would severely adversely affect the ability of the operating agent, APS, to operate, and the ability of PNM to earn a return on its interests in PVNGS. The “Deemed Loss Events” consist primarily of legal and regulatory changes (such as issuance by the NRC of specified violation orders, changes in law making the sale and leaseback transactions illegal, or changes in law making the lessors liable for nuclear decommissioning obligations). PNM believes that the probability of such “Events of Loss” or “Deemed Loss Events” occurring is remote for the following reasons: (1) to a large extent, prevention of “Events of Loss” and some “Deemed Loss Events” is within the control of the PVNGS participants through the general PVNGS operational and safety oversight process; and (2) other “Deemed Loss Events” would involve a significant change in current law and policy. PNM is unaware of any proposals pending or being considered for introduction in Congress, or in any state legislative or regulatory body that, if adopted, would cause any of those events. See Note 7.

Governance Factors

Provisions of PNMR's organizational documents, as well as several other statutory and regulatory factors, will limit another party's ability to acquire PNMR and could deprive PNMR's shareholders of the opportunity to receive a takeover premium for shares of PNMR's common stock.

PNMR's restated articles of incorporation and by-laws include a number of provisions that may have the effect of discouraging persons from acquiring large blocks of PNMR's common stock, or delaying or preventing a change in control of ~~PNMR. The material provisions that may have such an effect include:~~

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PNMR. The material provisions that may have such an effect include:


•	Authorization for the Board to issue PNMR's preferred stock in series and to fix rights and preferences of the series (including, among other things, voting rights and preferences with respect to dividends and other matters)


•	Advance notice procedures with respect to any proposal other than those adopted or recommended by the Board


•	Provisions specifying that only a majority of the Board, the chairman of the Board, the chief executive officer, or holders of at least one-tenth of all of PNMR's shares entitled to vote may call a special meeting of stockholders

Under the New Mexico Public Utility Act, NMPRC approval is required for certain transactions that may result in PNMR's change in control or exercise of control, including ownership of 10% or more of PNMR's voting stock. Certain acquisitions of PNMR's outstanding voting securities also require FERC approval.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


ITEM 2.	PROPERTIES

PNMR

The significant properties owned by PNMR include those owned by PNM and TNMP and are disclosed below.

PNM

See Sources of Power in Part I, Item. 1 Business above for information on PNM’s owned and leased capacity in electric generating stations. As of December 31, 2012, PNM owned, jointly owned, or leased, 3,189 circuit miles of electric transmission lines, 5,843 miles of distribution overhead lines, 5,631 cable miles of underground distribution lines (excluding street lighting), and 276 substations. PNM’s electric transmission and distribution lines are generally located within easements and rights-of-way on public, private, and Native American lands. PNM leases interests in PVNGS Units 1 and 2 and related property, Delta, EIP and associated equipment, data processing, communication, office and other equipment, office space, vehicles, and real estate. PNM also owns and leases service and office facilities in Albuquerque and in other areas throughout its service territory. See Note 7 for additional information concerning leases, including notices given to the lessors under the PVNGS Unit 1 leases in 2013 that PNM would renew the leases. See Note 9 for additional information about the Delta operating lease, including the potential purchase of Delta. As discussed in Note 16, PNM has agreed to exercise its option to purchase the leased portion of the EIP at expiration of the lease at fair market value of $7.7 million.

As of December 31, 2011, PNM owned, jointly owned, or leased, 3,189 circuit miles of electric transmission lines, 5,825 miles of distribution overhead lines, 5,548 cable miles of underground distribution lines (excluding street lighting), and 271 substations.

PNM’s electric transmission and distribution lines are generally located within easements and rights-of-way on public, private, and Native American lands. PNM leases interests in PVNGS Units 1 and 2 and related property, Delta, EIP and associated equipment, data processing, communication, office and other equipment, office space, vehicles, and real estate. PNM also owns and leases service and office facilities in Albuquerque and in other areas throughout its service territory. See Note 7.

TNMP

TNMP’s facilities consist primarily of transmission and distribution facilities located in its service areas. TNMP also owns and leases service and office facilities in other areas throughout its service territory. As of December 31, ~~2011~~2012, TNMP owned 966 circuit miles of overhead electric transmission lines, 7,~~054~~060 pole miles of overhead distribution lines, 1,~~059~~083 circuit miles of underground distribution lines, and 108 substations. Substantially all of TNMP's property is pledged to secure its first mortgage bonds. See Note 6.


ITEM 3.	LEGAL PROCEEDINGS

See Note 16 and Note 17 for information related to the following matters for PNMR, PNM, and TNMP, incorporated in this item by reference.

Note 16

• The Clean Air Act - Regional Haze – SJGS

• The Clean Air Act - Regional Haze – Four Corners

• ~~SJGS~~The ~~Operating~~Clean ~~Permit~~Air Act - Four Corners BART FIP Challenge

• ~~Citizen~~The ~~Suit Under the~~ Clean Air Act - WildEarth Guardians' Petition for Review of EPA's Approval of New Mexico Regional Haze SIP

• ~~Navajo~~The ~~Nation~~Clean ~~Environmental~~Air ~~Issues~~Act - SJGS Operating Permit Challenge

• ~~Four~~The ~~Corners~~Clean ~~New~~Air ~~Source~~Act ~~Review~~- Citizen Suit Under the Clean Air Act


•	The Clean Air Act - Navajo Nation Environmental Issues


•	The Clean Air Act - Four Corners New Source Review


•	Endangered Species Act

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•	Santa Fe Generating Station

• Coal Combustion Byproducts Waste Disposal –- Sierra Club Allegations


•	PVNGS Water Supply Litigation


•	San Juan River Adjudication

• ~~Western~~Complaint ~~United~~Against ~~States~~Southwestern ~~Wholesale~~Public ~~Power~~Service ~~Market~~Company

• ~~Begay~~Navajo v.Nations ~~PNM~~Allottee ~~et al~~Matters


•	Transmission Issues

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Table of Contents

Note 17

• PNM –- ~~Emergency~~Renewable ~~FPPAC~~Portfolio Standard

• PNM –- Renewable ~~Portfolio~~Energy ~~Standard~~Rider

• PNM –- Energy Efficiency and Load Management~~-Disincentives/Incentives Adder~~

• PNM-2011 –Integrated ~~2010~~Resource ~~Electric Rate Case~~Plan

• PNM –- ~~Transmission~~Emergency ~~Rate Case~~FFPAC

• PNM ~~– Firm~~-~~Requirements~~ ~~Wholesale~~Transmission ~~Customer~~ Rate Case

• ~~TNMP~~PNM ~~Competitive~~- ~~Transition~~Application ~~Charge~~for ~~True-Up~~Approvals ~~Proceeding~~to Purchase Delta

• ~~TNMP~~PNM –- ~~Interest~~Formula Transmission Rate ~~Compliance Tariff~~Case

• ~~TNMP~~PNM –- ~~2010~~Firm-Requirements Wholesale Customer Rate Case

• TNMP –- Advance Meter System Deployment and Surcharge Request

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


•	TNMP - Transmission Cost of Service Rates


ITEM 4.	MINE SAFETY DISCLOSURES

Not Applicable.

SUPPLEMENTAL ITEM - EXECUTIVE OFFICERS OF PNM RESOURCES, INC.

All officers are elected annually by the Board of PNMR. Executive officers, their ages as of February 22, ~~2012~~2013 and offices held with PNMR for the past five years, or other companies if less than five years with PNMR, are as follows:

Name	Age	Office	Initial Effective Date
P. K. Collawn	5354	Chairman, President, and Chief Executive Officer	January 2012
		President and Chief Executive Officer	March 2010
		President and Chief Operating Officer	August 2008
		President, Utilities	June 2007
		President and CEO - Public Service Company of Colorado, Xcel Energy	October 2005
C. N. Eldred	59	Executive Vice President and Chief Financial Officer	July 2007
C. N. Eldred	58	Executive Vice President and Chief Financial Officer	July 2007
P. V. Apodaca	61	Senior Vice President, General Counsel and Secretary	January 2010
		Senior Vice President and Chief Financial Officer	January 2006
P. V. Apodaca	60	Senior Vice President, General Counsel and Secretary	January 2010
		University Counsel, University of New Mexico	May 2006
R. E. Talbot	5152	Senior Vice President and Chief Operating Officer	January 2012
		Chief Operating Officer, Power Supply and Power Delivery - Indianapolis Power and Light Company	June 2011
		Senior Vice President, Power Supply - Indianapolis Power and Light Company	February 2007
		Senior Vice President, Customer Operations -Indianapolis Power and Light Company	August 2003
R. N. Darnell	55	Senior Vice President, Public Policy	December 2011
R. N. Darnell	54	Senior Vice President, Public Policy	December 2011
		Vice President, Regulatory Affairs	April 2008
		Director, Regulatory Administration South - Xcel Energy	January 2007
		Director, Pricing and Planning - Xcel Energy	October 2000
T. G. Sategna	59	Vice President and Corporate Controller	October 2003
T. G. Sategna	58	Vice President and Corporate Controller	October 2003

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Table of Contents

PART II

ITEM 5. MARKET FOR PNMR’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

PNMR’s common stock is traded on the New York Stock Exchange (Symbol: PNM). Ranges of sales prices of PNMR’s common stock, reported as composite transactions, and dividends declared on the common stock for ~~2011~~2012 and ~~2010~~2011, by quarters, are as follows:

Quarter Ended	Range ofSales Prices				Dividends
	High		Low		Per Share
2012
March 31	$	18.94	$	17.52	$	0.145
June 30	19.54		17.84		0.145
September 30	21.42		19.75		0.145
December 31	22.32		20.05		0.145
Fiscal Year	22.32		17.52		0.580
2011
March 31	$	15.16	$	12.96	$	0.125
June 30	17.10		14.46		0.125
September 30	17.14		12.75		0.125
December 31	19.17		15.81		0.125
Fiscal Year	19.17		12.75		0.500
2010
March 31	$	13.39	$	11.14	$	0.125
June 30	13.96		11.14		0.125
September 30	12.90		10.81		0.125
December 31	13.42		11.37		0.125
Fiscal Year	13.96		10.81		0.500

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.125 per share in July ~~2010~~2011 and $0.145 per share in July ~~2011~~2012, which are reflected as being in the second quarter above. The Board declared dividends on common stock considered to be for the third quarter of $0.125 per share in September ~~2010~~2011 and $0.145 per share in September ~~2011~~2012, which are reflected as being in the third quarter above. On December 64, ~~2011~~2012 and February 28, ~~2012~~2013, the Board declared quarterly dividends of $0.~~125~~145 and $0.~~145~~165 per share. PNMR targets a long-term dividend payout ratio of 50% to 60% of consolidated earnings. During the period it was outstanding, PNMR's Series A convertible preferred stock, ~~Series A~~ was entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the preferred stock had been converted into common stock.

On February 22, ~~2012~~2013, there were 1211,~~067~~469 holders of record of PNMR’s common stock. All of the outstanding common stock of PNM and TNMP is held by PNMR.

See Note 5 for a discussion on limitations on the payments of dividends and the payment of future dividends, as well as dividends paid by PNM and TNMP.

See Part III., Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Preferred Stock

PNM is not aware of any active trading market for its cumulative preferred stock. Quarterly cash dividends were paid on PNM’s outstanding cumulative preferred stock at the stated rates during ~~2010~~2011 and ~~2011~~2012. PNMR purchased and retired all of its outstanding convertible preferred stock, Series A, effective September 23, 2011. TNMP does not have any preferred stock outstanding.

Sales of Unregistered Securities

None.

Acquisition of Equity Securities

The following table provides information about PNMR purchases of equity securities that are registered by PNMR pursuant to Section 12 of the Exchange Act during the quarter ended December 31, 2011:

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Table of Contents

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased under the Plans or Programs
October 1, 2011 - October 31, 2011	—	—		—	$	156,525,493
November 1, 2011 - November 30, 2011(1)	7,019,550	$	17.90	7,019,550	$	—
December 1, 2011 - December 31, 2011	—	$	—	7,019,550	$	—
Total	7,019,550	$	17.90	7,019,550	$	—

(1) On September 23, 2011, PNMR announced that the Board approved a stock repurchase program under which equity purchases of up to $230.0 million were authorized. On October 5, 2011, PNMR completed the purchase from Cascade of all of PNMR's outstanding convertible preferred stock, Series A for an aggregate purchase price of $73.5 million. The preferred stock was not registered under Section 12 of the Exchange Act. The shares of preferred stock were convertible into 4,778,000 shares of PNMR's common stock. On November 10, 2011, PNMR completed the purchase of 7,019,550 shares of PNMR's common stock from Cascade for an aggregate purchase price of approximately $125.7 million. On November 22, 2011, PNMR announced that it had completed its current plans for equity purchases.

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Table of Contents


ITEM 6.	SELECTED FINANCIAL DATA

The selected financial data and comparative operating statistics for PNMR should be read in conjunction with the Consolidated Financial Statements and Notes thereto and MD&A. ~~PNMR results include results for the Twin Oaks business through May 31, 2007, when it was contributed to Optim Energy.~~ On January 30, 2009, PNM completed the sale of its gas operations, which are considered discontinued operations and excluded from continuing operations information in the table below. PNMR sold First Choice on November 1, 2011. First Choice is included in the following information through October 31, 2011.

PNM RESOURCES, INC. AND SUBSIDIARIES
	2011			2010			2009			2008			2007
	2012			2011			2010			2009			2008
	(In thousands except per share amounts and ratios)
Total Operating Revenues from Continuing Operations	$	1,~~700~~342,~~619~~403		$	1,~~673~~700,~~517~~619		$	1,~~647~~673,~~744~~517		$	1,~~959~~647,~~522~~744		$	1,~~914~~959,~~029~~522
Earnings (Loss) from Continuing Operations	$	~~190~~120,~~934~~125		$	~~(31~~190,~~124~~934	)	$	65(31,~~933~~124	)	$	~~(297~~65,~~565~~933	)	$	59(297,~~886~~565	)
Net Earnings (Loss)	$	~~190~~120,~~934~~125		$	~~(31~~190,~~124~~934	)	$	~~136~~(31,~~734~~124	)	$	~~(262~~136,~~937~~734	)	$	75(262,~~402~~937	)
Net Earnings (Loss) Attributable to PNMR	$	~~176~~105,~~359~~547		$	~~(45~~176,~~215~~359	)	$	~~124~~(45,~~316~~215	)	$	~~(270~~124,~~644~~316	)	$	74(270,~~874~~644	)
Earnings (Loss) from Continuing Operations Attributable to PNMR per Common Share
Basic	$	1.9832		$	(01.4998	)	$	(0.5849	)	$	(30.6658	)	$	0(3.7766	)
Diluted	$	1.9631		$	(01.4996	)	$	(0.5849	)	$	(30.6658	)	$	0(3.7666	)
Net Earnings (Loss) Attributable to PNMR per Common Share
Basic	$	1.9832		$	(01.4998	)	$	1(0.3649	)	$	(31.2436	)	$	0(3.9824	)
Diluted	$	1.9631		$	(01.4996	)	$	1(0.3649	)	$	(31.2436	)	$	0(3.9624	)
Cash Flow Data
Net cash flows from operating activities	$	~~292~~281,~~240~~349		$	~~287~~292,~~352~~240		$	87287,~~706~~352		$	8887,~~625~~706		$	~~223~~88,~~061~~625
Net cash flows from investing activities	$	19(285,~~778~~895	)	$	~~(275~~19,~~906~~778	)	$	~~379~~(275,~~726~~906	)	$	~~(320~~379,~~715~~726	)	$	(73320,~~531~~715	)
Net cash flows from financing activities	$	(~~312~~1,~~331~~560	)	$	(10312,~~683~~331	)	$	(~~593~~10,~~435~~683	)	$	~~354~~(593,~~943~~435	)	$	~~(255~~354,~~158~~943	)
Total Assets	$	5,~~204~~372,~~613~~583		$	5,~~225~~204,~~083~~613		$	5,~~359~~225,~~921~~083		$	65,~~147~~359,~~982~~921		$	56,~~872~~147,~~136~~982
Long-Term Debt, including current installments	$	1,~~674~~672,~~013~~290		$	1,~~565~~674,~~847~~013		$	1,~~567~~565,~~331~~847		$	1,~~584~~567,~~705~~331		$	1,~~681~~584,~~078~~705
Common Stock Data
Market price per common share at year end	$	1820.2351		$	1318.0223		$	1213.6502		$	1012.0865		$	2110.4508
Book value per common share at year end	$	1920.7619		$	1719.9076		$	1917.1390		$	19.13		$	2219.0313
Tangible book value per share at year end	$	16.2770		$	1416.1027		$	1514.3310		$	15.3133		$	1415.5931
Average number of common shares outstanding - diluted	8980,~~757~~417			9189,~~557~~757			91,~~671~~557			8391,~~468~~671			7783,~~928~~468
Dividends declared per common share	$	0.~~500~~580		$	0.500		$	0.500		$	0.~~605~~500		$	0.~~920~~605
Capitalization
PNMR common stockholders’ equity	48.39		%	4748.83		%	4947.68		%	49.36		%	5049.03		%
Convertible preferred stock	—			~~3.1~~—			3.01			3.0			—3.0
Preferred stock of subsidiary, without mandatory redemption requirements	0.3			0.43			0.34			0.3			0.3
Long-term debt	5150.48			4851.74			4748.17			47.41			4947.74
	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%

Note: The book value per common share at year end, tangible book value per share at year end, average number of common shares outstanding, and return on average common equity reflect the Series A convertible preferred stock as if it was converted into common stock at the date of its issuance on November 17, 2008 through September 23, 2011.

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2012		2011		2010			2009		2008
	(In thousands)
PNM Revenues
Residential	$	409,005	$	390,380	$	355,905		$	320,965	$	296,121
Commercial	413,332		386,383		355,699			330,552		326,408
Industrial	103,991		94,883		85,576			79,540		100,665
Public authority	25,495		23,970		21,302			19,770		19,135
Transmission	39,373		43,637		38,667			36,075		33,161
Firm-requirements wholesale	39,390		34,127		31,870			29,048		46,854
Other sales for resale	47,321		69,318		121,729			140,314		345,948
Mark-to-market activity	892		4,214		(3,599		)	151		56,560
Other	13,465		10,377		9,979			11,594		18,090
Total PNM Revenues	$	1,092,264	$	1,057,289	$	1,017,128		$	968,009	$	1,242,942
TNMP Revenues
Residential	$	103,255	$	100,290	$	83,645		$	74,739	$	71,673
Commercial	88,258		84,896		77,474			73,346		72,786
Industrial	13,405		13,065		12,342			12,113		13,849
Other	45,222		39,607		39,127			32,434		31,974
Total TNMP Revenues	$	250,140	$	237,858	$	212,588		$	192,632	$	190,282
First Choice Revenues
Residential	$	—	$	260,161	$	305,834		$	349,629	$	407,350
Commercial	—		166,498		159,785			160,998		205,518
Trading gains (losses)	—		—		(4		)	14		(49,931		)
Other	—		12,791		17,588			18,177		19,287
Total First Choice Revenues	$	—	$	439,450	$	483,203		$	528,818	$	582,224

Notes: PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.

First Choice is included through October 31, 2011, when it was sold by PNMR.

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2011			2010			2009		2008			2007
	2012		2011			2010		2009	2008
	(In thousands)
PNM MWh Sales
PNM Electric Revenues
Residential	3,323,544		3,402,842			3,361,472		3,264,378	3,221,894
Residential	$	390,380		$	355,905		$	320,965	$	296,121		$	265,418
Commercial	4,022,184		4,043,796			4,015,999		3,899,121	4,029,802
Commercial	386,383			355,699			330,552		326,408			294,755
Industrial	1,771,316		1,560,867			1,449,933		1,454,480	1,657,580
Industrial	94,883			85,576			79,540		100,665			99,970
Public authority	279,169		282,062			263,424		249,554	253,079
Public authority	23,970			21,302			19,770		19,135			15,112
Firm-requirements wholesale	651,972		650,356			677,508		689,740	1,123,539
Transmission	43,637			38,667			36,075		33,161			32,325
Other sales for resale	1,652,225		2,076,869			2,203,787		3,996,317	5,095,183
Firm-requirements wholesale	34,127			31,870			29,048		46,854			46,257
Total PNM MWh Sales	11,700,410		12,016,792			11,972,123		13,553,590	15,381,077
Other sales for resale	69,318			121,729			140,314		345,948			396,583
TNMP MWh Sales
Mark-to-market activity	4,214			(3,599		)	151		56,560			(44,318		)
Residential	2,714,511		2,862,337			2,699,601		2,582,555	2,533,025
Other	10,377			9,979			11,594		18,090			30,872
Commercial	2,353,135		2,360,998			2,260,505		2,216,870	2,206,155
Total PNM Electric Revenues	$	1,057,289		$	1,017,128		$	968,009	$	1,242,942		$	1,136,974
Industrial	2,727,126		2,578,877			2,241,452		1,983,165	2,094,789
TNMP Electric Revenues
Other	103,856		108,664			103,341		107,091	107,524
Residential	$	100,290		$	83,645		$	74,739	$	71,673		$	69,488
Total TNMP MWh Sales	7,898,628		7,910,876			7,304,899		6,889,681	6,941,493
Commercial	84,896			77,474			73,346		72,786			70,146
First Choice MWh Sales
Industrial	13,065			12,342			12,113		13,849			7,876
Residential	—		2,006,437			2,267,836		2,441,550	2,547,490
Other	39,607			39,127			32,434		31,974			32,911
Commercial	—		1,538,203			1,363,746		1,218,949	1,471,400
Total TNMP Revenues	$	237,858		$	212,588		$	192,632	$	190,282		$	180,421
Total First Choice MWh Sales	—		3,544,640			3,631,582		3,660,499	4,018,890
Altura Wholesale Revenues
Long-term contracts	$	—		$	—		$	—	$	—		$	65,395
First Choice Revenues
Residential	$	260,161		$	305,834		$	349,629	$	407,350		$	390,329
Commercial	166,498			159,785			160,998		205,518			206,576
Trading gains (losses)	—			(4		)	14		(49,931		)	(3,553		)
Other	12,791			17,588			18,177		19,287			7,343
Total First Choice Revenues	$	439,450		$	483,203		$	528,818	$	582,224		$	600,695

Notes: ~~Altura~~ ~~Wholesale~~Under ~~includes~~TECA, ~~Twin~~consumers ~~Oaks~~in ~~through~~Texas ~~May 31,~~can ~~2007,~~choose ~~when~~any ~~Altura~~REP ~~was~~to ~~contributed~~provide energy. TNMP delivers energy to ~~Optim~~consumers ~~Energy~~within its service area regardless of the REP chosen. Therefore, TNMP earns revenue for energy delivery and REPs earn revenue on the usage of that energy by its customers. The MWh reported above for TNMP and First choice include 836,599, 1,012,842, 1,131,907, and 1,563,260 MWh used by consumers of TNMP in 2011, 2010, 2009, and 2008, who chose First Choice as their REP.

PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.

First Choice is included through October 31, 2011, when it was sold by PNMR.

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2011		2010			2009		2008	2007
	2012			2011			2010		2009		2008
PNM Electric MWh Sales
PNM Customers
Residential	3450,~~402,842~~507		~~3,361,472~~	448,979		~~3,264,378~~	447,789	~~3,221,894~~	3445,~~208,593~~637		442,647
Commercial	454,~~043,796~~953		~~4,015,999~~	54,468		~~3,899,121~~	54,005	~~4,029,802~~	453,~~006,373~~787		53,059
Industrial	~~1,560,867~~251		~~1,449,933~~	252		~~1,454,480~~	260	~~1,657,580~~	~~1,920,086~~270		284
Public authority	282,062		263,424			249,554		253,079	236,651
Other sales for resale	36			28			46		44		55
Firm-requirements wholesale	650,356		677,508			689,740		1,123,539	1,121,695
Other	952			983			1,003		991		991
Other sales for resale	2,076,869		2,203,787			3,996,317		5,095,183	6,897,307
Total PNM Customers	506,699			504,710			503,103		500,729		497,036
Total PNM Electric MWh Sales	12,016,792		11,972,123			13,553,590		15,381,077	17,390,705
TNMP Consumers
TNMP Electric MWh Sales
Residential	193,550			192,356			190,809		188,812		187,888
Residential	2,862,337		2,699,601			2,582,555		2,533,025	2,520,605
Commercial	36,819			37,208			37,356		37,728		38,548
Commercial	2,360,998		2,260,505			2,216,870		2,206,155	2,195,962
Industrial	70			73			72		73		74
Industrial	2,578,877		2,241,452			1,983,165		2,094,789	1,927,934
Other	2,037			2,092			2,099		2,059		2,115
Other	108,664		103,341			107,091		107,524	100,581
Total TNMP Consumers	232,476			231,729			230,336		228,672		228,625
Total TNMP MWh Sales	7,910,876		7,304,899			6,889,681		6,941,493	6,745,082
First Choice Customers
Altura Wholesale MWh Sales
Residential	—			176,577			172,506		183,605		192,306
Long-term contracts	—		—			—		—	915,883
Commercial	—			44,485			41,695		41,371		45,125
First Choice MWh Sales
Total First Choice Customers	—			221,062			214,201		224,976		237,431
Residential	2,006,437		2,267,836			2,441,550		2,547,490	2,796,864
PNMR Generation Statistics
Commercial	1,538,203		1,363,746			1,218,949		1,471,400	1,590,229
Net Capability - MW, including wind and solar	2,537			2,547			2,631		2,711		2,713
Total First Choice MWh Sales	3,544,640		3,631,582			3,660,499		4,018,890	4,387,093
Coincidental Peak Demand - MW	1,948			1,938			1,973		1,866		1,901
Average Fuel Cost per MMBTU	$	2.308		$	2.267		$	2.064	$	1.895	$	2.404
BTU per KWh of Net Generation	10,289			10,441			10,237		10,277		10,269

Notes: ~~Altura~~ ~~Wholesale~~The ~~includes~~consumers ~~Twin~~reported ~~Oaks~~above ~~through~~for ~~May 31~~TNMP include 64,732, ~~2007~~70,366, ~~when~~80,718, ~~Altura~~and ~~was~~92,090 ~~contributed~~consumers toof ~~Optim~~TNMP ~~Energy~~for 2011, 2010, 2009, and 2008, who chose First Choice as their REP. These TNMP customers are also included in the First choice customers.

Under TECA, customers of TNMP Electric in Texas can choose First Choice or any other REP to provide energy. However, TNMP Electric delivers energy to customers within its service area regardless of the REP chosen. Therefore, TNMP Electric earns revenue for energy delivery and First Choice earns revenue on the usage of that energy by its customers. The MWh reported above for TNMP Electric and First choice include 836,599, 1,012,842, 1,131,907, 1,563,260, and 2,018,110 MWh used by customers of TNMP electric in 2011, 2010, 2009, 2008, and 2007, who have chosen first Choice as their REP.

PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.

First Choice is ~~included~~as ~~through~~of October 31, 2011, when it was sold by PNMR.

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Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2011		2010		2009		2008		2007
PNM Electric Customers
Residential	448,979		447,789		445,637		442,647		438,990
Commercial	54,468		54,005		53,787		53,059		52,780
Industrial	252		260		270		284		276
Other sales for resale	28		46		44		55		54
Other	983		1,003		991		991		1,023
Total PNM Electric Customers	504,710		503,103		500,729		497,036		493,123
TNMP Electric Consumers
Residential	192,356		190,809		188,812		187,888		183,260
Commercial	37,208		37,356		37,728		38,548		39,893
Industrial	73		72		73		74		76
Other	2,092		2,099		2,059		2,115		2,104
Total TNMP Consumers	231,729		230,336		228,672		228,625		225,333
Altura Wholesale Customers
Long-term	—		—		—		—		1
First Choice Customers
Residential	176,577		172,506		183,605		192,306		209,680
Commercial	44,485		41,695		41,371		45,125		48,689
Total First Choice Customers	221,062		214,201		224,976		237,431		258,369
PNMR Generation Statistics
Net Capability - MW, including wind and solar	2,547		2,631		2,711		2,713		2,655
Coincidental Peak Demand - MW	1,938		1,973		1,866		1,901		1,933
Average Fuel Cost per MMBTU	$	2.267	$	2.064	$	1.895	$	2.404	$	1.7539
BTU per KWh of Net Generation	10,441		10,237		10,277		10,269		10,850

Notes: Altura Wholesale includes Twin Oaks through May 31, 2007, when Altura was contributed to Optim Energy.

The consumers reported above for TNMP Electric include 64,732, 70,366, 80,718, 92,090, and 126,855 consumers of TNMP for 2011, 2010, 2009, 2008, 2007, who have chosen First Choice as their REP.

These TNMP Electric customers are also included in the First choice customers.

PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.

First Choice is as of October 31, 2011, when it was sold by PNMR.

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ITEM 7.	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-K General Instruction I (2). A reference to a “Note” in this Item 7 refers to the accompanying Notes to Consolidated Financial Statements included in Part II, Item 8, unless otherwise specified. Certain of the tables below may not appear visually accurate due to rounding.

MD&A FOR PNMR

EXECUTIVE SUMMARY

~~Company~~ Overview and Strategy

PNMR is a holding company with two regulated utilities serving approximately ~~730~~739,000 residential, commercial, and industrial customers and end-users of electricity in New Mexico and Texas. ~~PNM~~In ~~sold its gas operations on January 30, 2009 and by~~ the ~~end~~latter part of 2011, PNMR ~~had~~ exited both of its competitive businesses, First Choice and Optim Energy, and repositioned itself as a holding company solely operating its ~~regulated~~ electric utilities, PNM and TNMP. Financial results for 2011 included First Choice through October 31, 2011. Optim Energy had no impact on 2011 because it was written off in 2010, and PNMR had no further financial commitment to Optim Energy.

Strategic Goals

PNMR is focused on achieving the following strategic goals:


•	Earning authorized returns on its regulated businesses


•	Continuing to improve credit ratings


•	Providing a top-quartile total return to investors

~~PNMR's~~In ~~success~~conjunction inwith ~~accomplishing~~ these ~~strategic~~ goals, ~~is highly dependent on continued favorable regulatory treatment for its regulated utilities. Both~~ PNM and TNMP ~~seek~~are ~~cost~~dedicated recovery for their investments through general rate cases and various rate riders. The PUCT has approved mechanisms that allow for recovery of capital invested in transmission and distribution projects without having to ~~file a general rate case. This allows for more timely recovery of amounts invested in TNMP's systems.~~ :

~~PNM~~• ~~and~~Achieving ~~TNMP~~industry-leading ~~have~~safety ~~recently~~performance ~~completed~~and ~~rate~~customer proceedings before their state regulators. PNM has two rate cases pending before FERC. Additional information about all rate filings is provided in Note 17. A recap of these proceedings is as follows:satisfaction

~~PNM~~• Maintaining strong plant performance and reliability

•Earning ~~NMPRC~~Authorized ~~proceedings~~Returns on Regulated Businesses

◦PNMR's ~~2012~~success ~~Renewable~~in ~~Energy~~accomplishing ~~Rate~~its ~~Rider~~strategic -goals ~~surcharge~~is tohighly ~~recover~~dependent ~~approximately~~on ~~$95~~continued ~~million~~favorable ofregulatory ~~PNM's~~treatment ~~investment~~for in its ~~22MW~~utilities. The ~~solar~~Company ~~facility~~has ~~and~~multiple ~~other~~strategies ~~NMPRC~~to ~~approved~~achieve ~~renewable~~favorable ~~energy~~regulatory ~~costs~~treatment, toall beof ~~implemented~~which inhave ~~August~~as ~~2012~~their foundation a focus on the basics: managing the Company's business and serving our customers well, ~~subject~~while engaging stakeholders to ~~NMPRC~~build ~~approval~~productive relationships.

◦Both ~~2010~~PNM ~~Electric~~and ~~Rate~~TNMP ~~Case~~seek -cost ~~$72~~recovery for their investments through general rate cases and various rate riders.1 The ~~million~~PUCT ~~increase~~has approved mechanisms that allow for recovery of capital invested in ~~annual~~transmission ~~non-fuel~~and ~~revenues~~distribution ~~effective~~projects ~~August~~without ~~21,~~having to file a general rate case and allow for more timely recovery of amounts invested in TNMP's systems. In 2011, PNM made significant progress toward the goal of achieving authorized returns for its retail customers. In 2012, PNM saw additional progress toward achieving authorized returns for its transmission and generation customers regulated by FERC.

◦PNM ~~2008~~and ~~Electric~~TNMP ~~Rate~~completed ~~Case~~several -rate ~~$77.1~~proceedings ~~million~~before ~~increase~~their state regulators in ~~annual~~2011 ~~non-fuel~~and ~~revenues,~~2012. PNM ~~implemented~~has ~~65%~~two onrate ~~July~~cases 1,pending ~~2009~~before FERC and ~~35%~~one onthat ~~April~~was 1,completed ~~2010~~in early 2013. Additional information about rate filings is provided in Note 17.

•PNM ~~FERC~~previously ~~proceedings~~announced that it intended to file a request for an increase in the rates charged to New Mexico retail customers in mid-2013, but is currently re-evaluating when this filing will occur, partially due to the lack of clarity around the timing and amount of capital that will be required for BART at SJGS, as discussed below, and improved operating results at PNM.

◦Fair ~~Transmission~~and ~~Rate~~timely ~~Case~~rate -treatment ~~$11~~from regulators is crucial to achieving PNMR's strategic goals because it leads to PNM and TNMP earning their allowed returns.1 PNMR ~~million~~believes ~~requested~~that ~~annual~~if ~~increase~~the inutilities ~~revenues~~earn their allowed returns, ~~implemented~~it ~~June~~would 1be viewed positively by rating agencies and would further improve credit ratings, ~~2011~~which could lower costs to customers. Also, ~~subject~~earning allowed returns should result in increased earnings for PNMR, which should lead to ~~refund~~increased ~~pending~~total ~~FERC~~returns ~~final~~to ~~determination~~investors.

◦PNM's ~~Firm-Requirements~~interest ~~Wholesale~~in ~~Customer~~PVNGS ~~Rate~~Unit ~~Case~~3 -is $8excluded from NMPRC jurisdictional rates.7 ~~million~~While ~~requested~~PVNGS ~~annual~~Unit ~~increase~~3's financial contribution is not calculated in ~~revenues~~the toauthorized bereturns ~~implemented~~on ~~April~~its ~~14,~~regulated ~~2012~~business, ~~subject~~it toimpacts ~~refund~~PNM's ~~pending~~earnings ~~FERC~~and ~~final~~has ~~determination~~demonstrated

~~TNMP~~A- 26

•Table ~~PUCT~~of ~~proceedings~~Contents

◦to ~~AMS~~be ~~Cost~~a ~~Recovery~~valuable -asset. Power ~~surcharge~~generated tofrom ~~recover~~PNM's ~~$113.~~134 MW interest in PVNGS Unit 3 ~~million~~is ~~over~~currently 12sold ~~years~~into ~~beginning~~the ~~August~~wholesale ~~11,~~market ~~2011~~and any earnings or losses are attributable to shareholders.

◦Continuing ~~2010~~to ~~Rate~~Improve ~~Case~~Credit ~~- $10.25 million increase in revenues effective February 1, 2011~~Ratings

◦PNM ~~Transmission~~is ~~Cost~~committed ~~Recovery~~to -maintaining $5investment grade credit ratings.5 See ~~million~~the ~~increase~~subheading Liquidity included in ~~revenues~~the ~~effective~~full ~~May~~discussion 14of Liquidity and Capital Resources below for the specific credit ratings for PNMR, ~~2010~~PNM, and TNMP. On April 13, 2012, S&P raised the corporate credit rating for PNMR as well as the senior debt ratings for PNMR and TNMP and the preferred stock rating for PNM. S&P changed the outlook to stable for all entities.

◦Providing ~~2008 Rate Case~~ Top-Quartile ~~$12.7~~Total ~~million~~Returns ~~increase~~to ~~in revenues effective September 1, 2009~~Investors

PNMR's strategic goal to provide top quartile total return to investors is based on five-year ongoing EPS growth along with five-year average dividend yield. Top quartile total return currently is equal to an average annual rate of 10 percent to 13 percent. The annual common stock dividend was raised by 16 percent in February 2012 and 14 percent in February 2013.

PNMR's long-term target is a dividend payout ratio of 50 percent to 60 percent of its ongoing earnings. Ongoing earnings, which is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP. PNMR expects to provide above-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target. The PNMR board will continue to evaluate the dividend on an annual basis, considering sustainability and growth, capital planning, and industry standards.

Business Focus

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

To accomplish this, PNMR works closely with customers, stakeholders, legislators, and regulators to ensure that our resource plans and infrastructure investments benefit from robust public dialogue and balance the diverse needs of our communities.

Reliable and Affordable Power

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

Investing in PNM's and TNMP's infrastructure is critical to ensure reliability and meet future energy needs. Both utilities have long-established records of providing customers with top-tier electric reliability. In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through the end of 2012, TNMP had completed installation of more than 75,000 smart meters. TNMP's deployment is expected to be completed in 2016.

As part of the State of Texas' long-term initiative to create a smart electric grid, the smart meter rollout will ultimately give consumers more energy consumption data and help them make more informed decisions. In 2013, TNMP will install a new outage management system that will leverage capabilities of the smart meters to enhance the company's responsiveness to outages.

During the 2010 to 2012 period, PNM and TNMP together invested $803.7 million in substations, power plants, and transmission and distribution systems in New Mexico and Texas. In 2012, PNM announced the site for its planned 40 MW natural gas-fired peaking generating station. Construction is expected to begin in 2014, with the facility going into service in 2016. PNM also announced an agreement to purchase Delta, a 132 MW gas-fired peaking facility, which has served PNM jurisdictional needs under a 20-year purchase power agreement since 2000.

Environmentally Responsible Power

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

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


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

•Increasing energy efficiency participation

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Table of Contents

~~Fair~~ ~~and~~Renewable timely rate treatment from regulators is crucial to achieving PNMR's strategic goals because it leads to PNM and TNMP earning their allowed returns. PNMR believes that if the regulated utilities earn their allowed returns, it would be viewed positively by rating agencies and would further improve credit ratings, which could lower costs to customers. Also, earning allowed returns should result in increased earnings for PNMR, which should lead to increased total returns to investors. In 2011, PNMR common stock appreciated 40.0% and outpaced the appreciation in the S&P 500 and S&P 400 Utilities indices. Energy

~~PNM's~~In ~~interest~~2012, inPNM ~~PVNGS~~filed ~~Unit~~and 3the isNMPRC ~~permanently~~approved ~~excluded~~PNM's ~~from~~2013 ~~NMPRC~~renewable ~~jurisdictional~~procurement ~~rates~~strategy. ~~While~~The ~~PVNGS~~approved ~~Unit~~strategy 3will almost double PNM's ~~financial~~solar ~~contribution~~capacity iswith ~~not~~the ~~calculated~~addition inof ~~the~~21.5 ~~authorized~~MW ~~returns~~of onutility-owned ~~its~~solar ~~regulated~~capacity ~~business,~~estimated itcost ~~impacts~~of ~~PNM's~~almost ~~earnings~~$50 ~~and~~million. ~~has~~In ~~demonstrated~~addition to bethe solar expansion, the 2013 proposal includes a ~~valuable~~20-year ~~asset. Power~~agreement ~~generated~~to purchase energy from ~~the~~a ~~134~~geothermal MWfacility ~~unit~~to isbe ~~currently~~built ~~sold~~near ~~into~~Lordsburg. ~~the~~The ~~wholesale~~10 ~~market~~MW ~~and~~facility ~~any~~will ~~earnings~~be orthe ~~losses~~first ~~are~~geothermal ~~attributable~~project tofor ~~shareholders~~the PNM system.

~~Exit~~In ~~from~~addition ~~Competitive~~to ~~Businesses~~the 22 MW of solar currently available through the five plants constructed in 2011, PNM also owns a sixth facility, the 500-KW PNM Prosperity Energy Storage Project, which uses advanced batteries to store solar power and dispatch the energy either during high-use periods or when solar production is limited. The project features one of the largest combinations of battery storage and PV energy in the nation and involves extensive research and development of smart grid concepts with the Electric Power Research Institute, East Penn Manufacturing Co., Northern New Mexico College, Sandia National Laboratories, and the University of New Mexico. When the facility went online in September 2011, it was the nation's first solar storage facility fully integrated into a utility's power grid.

AsPNM's aresource ~~result~~portfolio ofincludes the ~~exit~~purchase of 204 MW of wind power. PNM also purchases power from ~~its~~a ~~competitive~~customer-owned ~~businesses,~~distributed ~~First~~solar ~~Choice~~generation ~~and~~program ~~Optim~~having ~~Energy,~~an ~~PNMR's~~installed ~~business~~capacity ~~model~~of is19.8 ~~centered~~MW onat ~~its~~the ~~regulated~~end ~~electric~~of ~~utilities~~2012. ~~The~~Distributed ~~elimination~~generation, ofwind, ~~the~~and ~~competitive~~solar ~~businesses~~power ~~should~~are ~~reduce~~key ~~PNMR's~~means ~~risk~~for PNM to meet the RPS established by the REA and ~~earnings~~related ~~volatility~~regulations issued by the NMPRC. ~~Additional~~These ~~discussion~~rules ~~about~~require ~~the~~a ~~exit~~utility to achieve prescribed levels of energy sales from renewable sources within its generation mix, if that can be accomplished without exceeding the ~~competitive~~RCT ~~businesses~~cost islimit ~~found~~set inby ~~Note~~the 2NMPRC, ~~and~~which ~~Note~~aims ~~21.~~to moderate the cost to consumers when utilities use more renewable resources.

~~Credit~~PNM ~~Ratings~~sought and ~~Liquidity~~received a waiver from the NMPRC excusing it from meeting the RPS in 2012 because the cost to achieve the full RPS would exceed the RCT. The 2013 plan will enable PNM to comply with the statutory RPS amount in 2013, but required a variance from the NMPRC's diversity requirements in 2013 while the proposed geothermal facilities are being constructed. This plan is expected to enable PNM to achieve full RPS quantity and diversity compliance by 2014 without exceeding the RCT. PNM will continue to procure renewable resources while balancing the bill impact to customers in order to meet New Mexico's escalating RPS requirements.

~~See~~SJGS the subheading Liquidity included in the full discussion of Liquidity and Capital Resources below for the specific credit ratings for PNMR, PNM, and TNMP. As a result of recent rate cases for PNM and TNMP and the new business direction that is expected to provide less risk, S&P raised the credit ratings for PNMR, PNM, and TNMP and changed the outlook for each entity to positive on September 26, 2011. On November 1, 2011, Moody's raised the credit ratings for PNMR and TNMP while retaining the outlook at stable.

~~Business~~PNM ~~Principles~~continues its efforts to comply with the EPA regional haze rule in a manner that minimizes the cost impact to customers while still achieving broad environmental benefits. The FIP for regional haze requires the installation of SCRs on all four units at SJGS by September 2016. PNM is challenging EPA's proposal in court and administratively within EPA.

In ~~addition~~order to ~~its~~keep ~~strategic~~costs ~~goals~~to customers as low as possible while also reducing visibility impairment related to regional haze, ~~three~~PNM ~~principles~~has ~~drive~~supported ~~PNMR's~~the ~~business~~installation ~~strategy~~of ~~and~~SNCRs ~~decision-making:~~at SJGS, a technology proposed by the State of New Mexico to meet the regional haze regulations. Additional information about BART at SJGS is contained in Note 16.

•On ~~Contribute~~February 15, 2013, PNM, NMED, and EPA agreed to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the ~~economic~~non-binding ~~vitality~~agreement would result in the retirement of SJGS Units 2 and 3 by the ~~communities~~end weof ~~serve~~2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP. PNM would also build a natural gas plant in the Four Corners region to partially replace the capacity from the retired coal units. Implementing this plan would include:

• ~~Demonstrate~~NMED ~~environmental~~development ~~stewardship~~of a revised SIP

• ~~Exhibit~~Approval ~~social~~of ~~responsibility~~the revised SIP by EIB

• InEPA ~~support~~approval of these principles, PNMR works closely with customers, stakeholders, legislators, and regulators to ensure that our resource plans and infrastructure investments benefit from robust public dialogue and balance the ~~diverse~~revised ~~needs of our communities.~~ SIP

~~Economic~~• ~~Vitality~~NMPRC approval of the retirement of Units 2 and 3 and plans to acquire replacement power

~~PNMR~~The ~~and~~term ~~its~~sheet ~~utilities~~setting ~~are~~forth ~~keenly~~the ~~aware~~non-binding ofagreement ~~the~~projects ~~roles~~EIB ~~they~~approval ~~play~~for inOctober ~~enhancing~~2013, ~~economic~~with ~~vitality~~EPA final action in ~~their~~late ~~New~~2014. Contemporaneously ~~Mexico~~with ~~and~~the ~~Texas~~signing ~~service~~of ~~territories. We~~the ~~believe~~non-binding ~~there~~agreement, isEPA aindicated ~~direct~~in ~~connection~~writing ~~between~~that ~~electric~~if ~~infrastructure~~the ~~and~~above ~~economic~~plan ~~growth. When~~does ~~considering~~not ~~expanding~~move orforward ~~relocating~~due to ~~other~~circumstances ~~communities,~~outside ~~businesses~~of ~~consider~~the ~~energy~~control ~~affordability~~of PNM and ~~energy~~NMED, ~~reliability~~EPA towill bework ~~important~~with ~~factors.~~the ~~PNM~~state and ~~TNMP~~PNM ~~strive~~ to ~~balance~~create ~~service~~a ~~affordability~~reasonable ~~with~~FIP ~~infrastructure~~compliance ~~investment~~schedule to ~~maintain~~reflect athe ~~high~~time ~~level~~used ofto ~~electric~~develop ~~reliability~~the new state plan. ~~The~~PNM ~~utilities~~is also ~~work~~exploring topotential ~~ensure~~additional ~~that~~areas ~~rates~~of ~~reflect~~relief, ~~actual~~including ~~costs~~relief offrom ~~providing~~the ~~service.~~Tenth Circuit.

~~Investing~~In inconnection ~~PNM's~~with ~~and~~the ~~TNMP's~~implementation ~~infrastructure~~of isthe ~~critical~~plan, toretirement ~~ensure~~of ~~reliability~~SJGS ~~and~~Units ~~meet~~2 ~~future~~and ~~energy~~3 ~~needs. In~~could ~~September~~result ~~2011,~~in ~~TNMP~~shifts ~~began its deployment of smart meters~~ in ~~homes~~ownership ~~and~~among ~~businesses~~SJGS ~~across~~owners ~~its~~as ~~Texas~~may ~~service~~be ~~area. As~~agreed ~~part~~upon ofby the ~~state~~owners of ~~Texas'~~the ~~long-term~~affected ~~initiative~~units. Owners toof ~~create a smart electric grid,~~ the ~~smart~~affected ~~meter~~units ~~rollout~~also ~~will~~may ~~ultimately~~seek ~~give~~approvals ~~consumers~~of ~~more~~their ~~energy~~utility ~~consumption~~commissions ~~data~~or ~~and~~governing ~~help them make more informed decisions~~boards. ~~TNMP's deployment is expected to be completed in 2016.~~

During the 2009 to 2011 period, PNM and TNMP together invested $828.9 million in substations, power plants, and transmission and distribution systems in New Mexico and Texas. Both utilities have long-established records of providing customers with top-tier electric reliability.

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Table of Contents

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

~~For~~This ~~years,~~plan ~~PNMR~~would achieve similar visibility improvements as the installation of SCRs on all four units at SJGS. It has ~~demonstrated~~the ~~its~~added ~~commitment~~advantage of reducing other emissions beyond NOx, including SO2, particulate matter, CO2, and mercury. Detailed replacement power strategies also would be finalized. PNM believes adequate replacement power alternatives will be available to ~~environmental~~meet ~~stewardship~~its generation needs and ensure reliability. ~~PNMR's~~PNM ~~environmental~~can ~~objectives~~provide ~~focus~~no onassurance ~~four~~that ~~areas:~~the requirements of this plan will be accomplished at all or within the required timeframes.

•In ~~Deploying~~order ~~renewable~~to ~~energy~~be able to install SCRs on all four units of SJGS by the compliance deadline set forth in the FIP, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, has been suspended through November 1, 2014.

•In ~~Reducing~~addition ~~emissions~~to ~~from~~the ~~existing~~regional ~~fossil~~haze rule, SJGS is required to comply with other rules currently being developed or implemented that affect coal-~~fuel~~fired ~~power~~generating ~~plants~~units. Because of $320 million in environmental upgrades completed in 2009, SJGS is well positioned to outperform the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. The major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO2, particulate matter, and mercury. PNM's share of the costs of these upgrades was $161 million. Since 2006, SJGS has reduced NOx emissions by 43 percent, SO2 by 69 percent, particulate matter by 64 percent, and mercury by 99 percent.

•Energy ~~Increasing energy efficiency participation~~Efficiency

•Energy ~~Reducing~~efficiency ~~waste~~also plays a significant role in helping to keep customers' electricity costs low and meeting their energy needs. PNM's and TNMP's energy efficiency and load management portfolios continue to be robust. In 2012, annual energy saved as a result of PNM's portfolio of energy efficiency programs was approximately 71,000 MWh. This is equivalent to the consumption of approximately 9,600 homes in PNM's service territory. PNM's load management and energy efficiency programs also help lower peak demand requirements. TNMP's energy efficiency programs in 2012 resulted in energy savings totaling an estimated 12,839 MWh.

InCreating ~~2011,~~Value ~~PNM~~for ~~completed~~Customers ~~its $95 million investment in a utility-owned renewable energy project when five utility-scale solar facilities went online. The five solar sites located in Alamogordo, Deming, Los Lunas, Las Vegas,~~ and Albuquerque provide a combined 22 MW of power. A sixth facility, the 500-KW PNM Prosperity Energy Storage Project, uses advanced batteries to store solar power and dispatch the energy either during high-use periods or when solar production is limited. The project features one of the largest combinations of battery storage and photovoltaic energy in the nation and involves extensive research and development of smart grid concepts with the Electric Power Research Institute, East Penn Manufacturing Co., Northern New Mexico College, Sandia National Laboratories and the University of New Mexico. When the facility went online in September 2011, it was the nation's first solar storage facility fully integrated into a utility's power grid. Communities

InThrough ~~addition~~outreach, ~~PNM's~~collaboration, ~~resource portfolio includes the purchase of 200 MW of wind power. Both wind~~ and ~~solar~~various ~~power~~community-oriented are key means for PNM to meet the RPS established by the REA and related regulations issued by the NMPRC. These rules require a utility to achieve prescribed levels of energy sales from renewable sources within its generation mixprograms, ifPNMR ~~that~~has ~~can be accomplished without exceeding the RCT cost limit set by the NMPRC, which aims to moderate the cost to consumers when utilities use more renewable resources. PNM sought and received~~ a ~~waiver~~demonstrated ~~from~~commitment ~~the NMPRC excusing it from meeting the RPS in 2012 because the cost~~ to ~~achieve~~build ~~the~~productive ~~full~~relationships ~~RPS~~with ~~would exceed the RCT. However~~stakeholders, ~~PNM~~including ~~will continue to procure renewable resources while balancing the bill impact to~~ customers, inregulators, ~~order~~legislators, toand ~~meet New Mexico's escalating RPS requirements~~intervenors.

~~PNM's~~Building ~~SJGS~~off ~~near~~work ~~Farmington,~~that ~~N.M.,~~began isin ~~one~~2008, ofPNM ~~the~~has ~~top~~continued ~~performers~~outreach inefforts ~~the nation with respect~~ to ~~mercury~~connect ~~removal. The~~low-income ~~plant~~customers ~~outperforms~~with ~~the~~nonprofit ~~mercury~~community ~~limit~~service ~~recently~~providers ~~imposed~~offering bysupport ~~EPA. Major~~and ~~environmental~~help ~~upgrades~~with onsuch ~~each~~needs ofas utility ~~the~~bills, ~~four units at SJGS~~food, ~~which were completed in early 2009~~clothing, ~~have~~medical ~~significantly reduced emissions of NOx~~programs, ~~SO2,~~services ~~particulate~~for ~~matter~~seniors, and ~~mercury~~weatherization. In 2012, PNM's ~~share~~hosted of23 ~~the~~community ~~costs~~events ofthroughout ~~these~~its ~~upgrades~~service ~~was~~territory ~~$161~~to ~~million~~assist low-income customers. ~~From~~Furthermore, ~~2006~~the toPNM ~~2010,~~Good ~~SJGS~~Neighbor ~~reduced~~Fund ~~NOx~~provided ~~emissions~~$1.0 bymillion ~~44%,~~of ~~SO2~~assistance bywith ~~71%,~~utility ~~particulate~~bills ~~matter~~to ~~by 72%~~10,216 ~~and~~families ~~mercury~~in ~~by 87%~~2012.

InThe ~~order~~PNM toResources ~~keep~~Foundation ~~costs~~helps tononprofits ~~customers~~become asmore ~~low~~energy asefficient ~~possible~~through ~~while~~Reduce ~~also~~Your ~~reducing~~Use ~~emissions~~grants. For ~~from~~2012, ~~fossil-fuel~~the ~~generation,~~foundation ~~PNM~~awarded ~~has~~$0.3 ~~proposed~~million ~~the~~to ~~installation~~support of55 ~~SNCR~~projects ~~technology~~in atNew ~~SJGS,~~Mexico ~~which~~to ~~technology~~provide isshade ~~also~~structure ~~proposed~~installations, bywindow ~~the~~replacements, ~~State~~and ofefficient ~~New~~appliance ~~Mexico~~purchases. ~~However,~~Since the ~~EPA~~program's ~~has~~inception ~~issued~~in ~~its~~2008, ~~FIP~~Reduce ~~requiring~~Your ~~SCR~~Use ~~technology~~grants tohave beprovided ~~installed,~~nonprofit ~~which~~agencies ~~PNM~~in ~~estimates~~New ~~would~~Mexico ~~cost~~with ~~about~~a 10total ~~times~~of ~~as much as installing SNCRs~~$1. ~~PNM~~1 ismillion ~~challenging~~of ~~EPA's proposal in the courts and administratively within EPA~~support.

~~Energy~~PNM ~~efficiency~~ also ~~plays~~expanded aits ~~significant~~environmental ~~role~~stakeholder outreach in ~~helping~~2012, topiloting ~~keep~~small ~~customers'~~environmental ~~electricity~~stakeholder ~~costs~~dialogue ~~low~~groups ~~and~~on ~~meeting~~key ~~their~~issues ~~energy~~such ~~needs. PNM's~~as ~~and~~renewable ~~TNMP's~~ energy ~~efficiency~~ and ~~load~~energy ~~management~~efficiency ~~portfolios~~planning. PNM ~~continue~~also toemployed beproactive ~~robust. In~~stakeholder ~~2011,~~outreach ~~annual~~in ~~energy~~two ~~saved~~key asprojects a- ~~result~~the development of the PNM's ~~portfolio~~renewable of energy ~~efficiency~~procurement ~~programs~~plans ~~was~~that ~~approximately~~involved ~~58,900~~distributed ~~MWh. This~~solar isenergy ~~equivalent~~developers toearly in the ~~consumption~~conversation and the siting of ~~approximately~~the ~~7,700~~planned ~~homes~~gas-fired peaking generation facility in ~~PNM's~~Valencia ~~service~~County, ~~territory. PNM's~~which ~~load~~featured ~~management~~in-depth community involvement and ~~energy~~education ~~efficiency~~early ~~programs~~in ~~also~~the ~~help~~planning ~~lower~~stages ~~peak~~of ~~demand~~the ~~requirements~~project. ~~TNMP's~~ ~~energy~~In ~~efficiency~~both ~~programs~~cases inhighly ~~2011~~favorable ~~resulted~~outcomes inwere ~~energy~~achieved, ~~savings~~and ~~totaling~~controversial annegative ~~estimated~~media ~~13,435~~coverage ~~MWh.~~was virtually eliminated.

InEconomic 2008, PNMR established a three-year waste-reduction goal in which all facilities were to maintain recycling programs and identify significant waste streams. The target called for at least 75% of facilities to implement plans to reduce a minimum of one waste stream by 15% below 2009 levels. By the end of 2011, more than 87% of PNMR facilities had achieved the waste-reduction goal. Factors

~~Social~~In ~~Responsibility~~2012, PNM experienced a decrease in weather-normalized, retail load of 0.7% and TNMP experienced an increase in weather-normalized, retail load of 3.7% compared to 2011. In recent years, New Mexico and Texas have fared better than the national average in unemployment. However, New Mexico's figures may be misleading due to people dropping out of the

Through outreach, collaboration, and various community-oriented programs, PNMR continues to make significant progress in two of its key focus areas of low-income assistance and energy efficiency support in New Mexico and Texas.

Building off work that began in 2008, outreach efforts in 2011 included numerous community events that connected low-income customers with non-profit community service providers offering support and help with such needs as utility bills, food,

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~~clothing,~~workforce. Employment ~~medical~~growth ~~programs,~~is ~~services~~much ~~for~~more ~~seniors~~telling, ~~and~~as ~~weatherization. Additionally,~~Texas ~~four~~leads of the ~~largest~~way ~~grants~~with ~~awarded~~growth byrates ~~PNMR~~well ~~supported~~above ~~nonprofits~~the innational ~~various~~rate ~~areas~~while ~~such~~New ~~as:~~Mexico's employment is relatively flat.

• Adult literacy

• Assistance for families trying to emerge from poverty

• Food rescue from restaurants and grocers to help feed those in need

• Assistance for low-income individuals to build a home, start a small business, or pursue higher education

In 2011, the PNM Good Neighbor Fund provided $1.2 million of assistance with utility bills to 9,907 families. Further, as part of the settlement in its 2010 Electric Rate Case, PNM voluntarily agreed to contribute an additional $1.3 million to the Good Neighbor Fund. This fund, along with additional collaboration with various other agencies, has helped to reduce the electricity affordability gap for many vulnerable customer groups such as seniors, young families, and medically challenged households.

The PNM Resources Foundation helps nonprofits become more energy efficient through Reduce Your Use grants. In 2011, the Foundation awarded more than $0.3 million to support 87 projects in New Mexico and Texas that helped purchase energy efficiency appliances and install high-performance windows and solar panels. Since the program's inception in 2008, Reduce Your Use grants have provided nonprofit agencies with $1.0 million of support in New Mexico and Texas.

Economic Factors

In 2011, PNM and TNMP experienced weather-normalized, retail load growth of 1.4% and 1.3% over 2010. While growth was relatively modest, electricity demand in both utilities' service territories was positive in 2011 and 2010 and fared better than many other areas of the United States. New Mexico and Texas have surpassed the national average the past several years in other economic indicators such as unemployment and employment growth.

Rate Base Potential Growth

Based on the 5-year capital plan announced in December 2011, PNM expects rate base to grow at a 2% compound annual rate between 2011 and 2013. That growth figure could be 6% from 2011 through 2016 through additional potential capital investments. The largest of these involves possibly being required to install SCR technology to reduce emissions at SJGS and Four Corners. The addition of other facilities, such as renewable resources and peaking capacity, could also expand rate base. TNMP's compound annual rate base growth rate from 2011 through 2013 is estimated at 8%, predicated on the utility's 5-year capital plan announced in December 2011. A significant portion of the capital additions should be recovered through the transmission and distribution cost recovery mechanisms. PNMR will continue to carefully balance the potential rate base growth for PNM and TNMP with customer rate impacts.

Results of Operations

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

	Year Ended December 31,								Change
	2011		2010			2009			2011/2010			2010/2009
	2012		2011			2010			2012/2011			2011/2010
			(In millions, except per share amounts)
Earnings (loss) from continuing operations	$	176.4	$	(45.2	)	$	53.5		$	221.6		$	(98.7	)
Net earnings (loss)	$	105.5	$	176.4		$	(45.2	)	$	(70.9	)	$	221.6
Earnings from discontinued operations, net of income taxes	—		—			70.8			—			(70.8		)
Average common and common equivalent shares	80.4		89.8			91.6			(9.4		)	(1.8		)
Net earnings (loss)	$	176.4	$	(45.2	)	$	124.3		$	221.6		$	(169.5	)
Net earnings (loss) per diluted share	$	1.31	$	1.96		$	(0.49	)	$	(0.65	)	$	2.45
Average common and common equivalent shares	89.8		91.6			91.7			(1.8		)	(0.1		)
Earnings (loss) from continuing operations per diluted share	$	1.96	$	(0.49	)	$	0.58		$	2.45		$	(1.07	)
Net earnings (loss) per diluted share	$	1.96	$	(0.49	)	$	1.36		$	2.45		$	(1.85	)

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Table of Contents

The components of the changes in earnings (loss) from continuing operations attributable to PNMR by segment are:

	Change
	2011/2010			2010/2009
	2012/2011			2011/2010
	(In millions)
PNM Electric	$	(2.8	)	$	37.3
PNM	$	37.0		$	(2.8	)
TNMP Electric	6.3			3.8
TNMP	4.4			6.3
First Choice	0(24.1		)	~~(20~~0.41		)
Corporate and Other	95(88.12		)	~~(14~~95.71		)
Optim Energy, including impairment	~~122.9~~—			~~(104~~122.79		)
Net change	$	~~221~~(70.69	)	$	~~(98~~221.76	)

PNMR's operational results were affected by the following:

• Exit from unregulated businesses ~~and PNM Gas~~ - As discussed above, PNMR sold First Choice in 2011, resulting in a pre-tax gain of $174.9 million, which was included in the Corporate and Other segment. Additionally, PNMR wrote-off its investment in Optim Energy in 2010, recognizing a pre-tax impairment loss of $188.2 million. ~~Further, in January 2009, PNM completed the sale of PNM Gas, which is reflected as discontinued operations, realizing a pre-tax gain of $98.4 million.~~ In addition to the impacts of these transactions, results of operations only include ~~PNM Gas through January 30, 2009,~~ Optim Energy through December 31, 2010, and First Choice through October 31, 2011.

• Rate increases for PNM and TNMP - Additional information about these rate increases is provided in Note 17.

• ~~Other~~Decrease ~~factors - Other factors impacting results of operation for each segment are discussed under Results of Operations below. The decrease~~ in the number of common and common equivalent shares, is primarily due to PNMR's purchase of its equity as described in Note 6.


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

Liquidity and Capital Resources

~~During~~The ~~2011,~~Company ~~PNMR~~has ~~and PNM replaced their~~ revolving credit facilities ~~with~~that ~~new facilities. The new facilities~~ provide capacities for short-term borrowing and letters of credit of $300.0 million for PNMR and $400.0 million for PNM, both of which expire in October 2017. In addition, TNMP has a $75.0 million revolving credit facility, which expires in December 2015. Total availability for PNMR on a consolidated basis was $~~584~~603.90 million at February 22, ~~2012~~2013. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. PNMR also has intercompany loan agreements with each of its subsidiaries.

InThe ~~2011,~~Company ~~PNMR~~projects ~~completed~~that ~~the~~its ~~sale~~total capital requirements, consisting of ~~First~~construction ~~Choice. PNMR~~expenditures ~~used~~and ~~the~~dividends, ~~proceeds~~will oftotal $~~329~~2,047.34 million tofor ~~purchase 7~~2013-2017.0 The ~~million~~construction ~~shares~~expenditures ofinclude ~~its~~additional ~~outstanding~~renewable ~~common~~resources ~~stock~~anticipated to be required to meet the RPS, ~~all~~additional ~~$100.0~~peaking ~~million~~resources ofneeded ~~its~~to ~~outstanding~~meet ~~convertible~~needs ~~preferred~~outlined ~~stock,~~in ~~Series~~PNM's Acurrent IRP, and ~~$50~~environmental upgrades at Four Corners .0 This ~~million~~estimate does not include any amounts related to environmental upgrades at SJGS that ultimately may be required by EPA to address regional haze (Note 16) or expenditures that could be required to replace capacity should environmental control at SJGS involve shutdown of ~~its~~one ~~outstanding~~or 9more SJGS units.~~25%~~ ~~senior~~In ~~unsecured~~addition ~~notes~~to asinternal ~~well~~cash asgeneration, the Company anticipates that it will be necessary to ~~reduce~~obtain ~~short~~additional long-term ~~debt. Also,~~financing ~~PNM~~in ~~issued~~the ~~$160.0~~form ~~million~~ of ~~new~~debt ~~senior~~refinancing, ~~unsecured~~new ~~notes~~debt issuances, and/or ~~used~~new ~~the~~equity ~~proceeds~~in order to ~~reduce~~fund ~~short~~its capital requirements during the 2013-~~term~~2017 ~~debt~~period. ~~TNMP~~The ~~refinanced~~Company ancurrently ~~existing~~believes ~~$50.0~~that ~~million~~its ~~term~~internal ~~loan~~cash generation, ~~which~~existing ~~reduced~~credit ~~the~~arrangements, ~~interest~~and ~~rate~~access onto public and private capital markets will provide sufficient resources to meet the ~~debt~~Company's capital requirements.

~~The Company projects that its total capital requirements, consisting of construction expenditures and dividends, will total $1,540.4 million for 2012~~A-~~2016. This~~ estimate does not include any amounts related to environmental upgrades at SJGS or Four Corners that may be required by EPA to address regional haze (Note 16), additional renewable resources that may be required to meet the RPS, or additional peaking resources that may be needed to meet needs outlined in PNM's current IRP. In addition to internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing in the form of debt refinancing, new debt issuances, and/or new equity in order to fund its capital requirements during the 2012-2016 period. The Company currently believes that its internal cash generation, existing credit arrangements, and access to public and private capital markets will provide sufficient resources to meet the Company's capital requirements.30

~~RESULTS~~Table OFof ~~OPERATIONS~~Contents ~~- PNMR~~

RESULTS OF OPERATIONS

Segment Information

The following discussion is based on the segment methodology that PNMR’s management uses for making operating decisions and assessing performance of its various business activities. See Note 32 for more information on PNMR’s operating segments.

The following discussion and analysis should be read in conjunction with the 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 in Part I, Item 1 and to Part II, Item 7A. Risk Factors.

PNM

The table below summarizes operating results for PNM:



	Year Ended December 31,									Change
	2012			2011			2010			2012/2011			2011/2010
	(In millions)
Total revenues	$	1,092.3		$	1,057.3		$	1,017.1		$	35.0		$	40.2
Cost of energy	353.6			362.2			352.3			(8.6		)	9.9
Margin	738.6			695.1			664.9			43.5			30.2
Operating expenses	435.4			438.8			424.5			(3.4		)	14.3
Depreciation and amortization	97.3			94.8			92.3			2.5			2.5
Operating income	205.9			161.4			148.1			44.5			13.3
Other income (deductions)	26.5			19.9			31.6			6.6			(11.7		)
Net interest charges	(76.1		)	(75.3		)	(72.4		)	(0.8		)	(2.9		)
Earnings before income taxes	156.3			106.0			107.3			50.3			(1.3		)
Income (taxes)	(50.7		)	(37.4		)	(36.4		)	(13.3		)	(1.0		)
Valencia non-controlling interest	(14.1		)	(14.0		)	(13.6		)	(0.1		)	(0.4		)
Preferred stock dividend requirements	(0.5		)	(0.5		)	(0.5		)	—			—
Segment earnings	$	91.0		$	54.0		$	56.8		$	37.0		$	(2.8	)

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



	2012/2011 Change									2011/2010 Change
	Total Revenues			Cost of Energy			Margin			Total Revenues			Cost of Energy			Margin
	(In millions)
Retail rate increases	$	40.3		$	—		$	40.3		$	32.1		$	—		$	32.1
Retail load, fuel, and transmission	(15.9		)	(10.6		)	(5.4		)	28.3			10.7			17.5
Wholesale rate increase	4.0			—			4.0
Unregulated margins	(5.9		)	1.1			(7.0		)	(41.0		)	0.9			(41.9		)
Energy efficiency rider	8.9			—			8.9			13.0			—			13.0
Renewable rider	6.9			2.0			4.9			—			—			—
Net unrealized economic hedges	(3.3		)	(1.1		)	(2.2		)	7.8			(1.7		)	9.5
Total increase (decrease)	$	35.0		$	(8.6	)	$	43.5		$	40.2		$	9.9		$	30.2

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

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	Year Ended December 31,							Change
	2012		2011		2010			2012/2011			2011/2010
	(In millions, except customers)
Residential	$	409.0	$	390.4	$	355.9		$	18.6		$	34.5
Commercial	413.3		386.4		355.7			26.9			30.7
Industrial	104.0		94.9		85.6			9.1			9.3
Public authority	25.5		24.0		21.3			1.5			2.7
Transmission	39.4		43.6		38.7			(4.2		)	4.9
Firm-requirements wholesale	39.4		34.1		31.9			5.3			2.2
Other sales for resale	47.4		69.3		121.7			(21.9		)	(52.4		)
Mark-to-market activity	0.9		4.2		(3.6		)	(3.3		)	7.8
Other	13.4		10.4		9.9			3.0			0.5
	$	1,092.3	$	1,057.3	$	1,017.1		$	35.0		$	40.2
Average retail customers (thousands)	505.6		503.9		501.7			1.7			2.2

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

The table below summarizes operating results for PNM Electric:



	Year Ended December 31,			Change
	2012	2011	2010	2012/2011		2011/2010
	(Gigawatt hours)
Residential	3,323.5	3,402.8	3,361.5	(79.3	)	41.3
Commercial	4,022.2	4,043.8	4,016.0	(21.6	)	27.8
Industrial	1,771.3	1,560.9	1,449.9	210.4		111.0
Public authority	279.2	282.1	263.4	(2.9	)	18.7
Firm-requirements wholesale	652.0	650.4	677.5	1.6		(27.1	)
Other sales for resale	1,652.2	2,076.8	2,203.8	(424.6	)	(127.0	)
	11,700.4	12,016.8	11,972.1	(316.4	)	44.7

	Year Ended December 31,									Change
	2011			2010			2009			2011/2010			2010/2009
	(In millions)
Total revenues	$	1,057.3		$	1,017.1		$	968.0		$	40.2		$	49.1
Cost of energy	362.2			352.3			378.1			9.9			(25.9		)
Gross margin	695.1			664.9			589.9			30.2			75.0
Operating expenses	438.8			424.5			420.5			14.3			4.0
Depreciation and amortization	94.8			92.3			92.1			2.5			0.1
Operating income	161.4			148.1			77.3			13.3			70.9
Other income (deductions)	19.9			31.6			37.4			(11.7		)	(5.9		)
Net interest charges	(75.3		)	(72.4		)	(69.1		)	(2.9		)	(3.3		)
Earnings before income taxes	106.0			107.3			45.6			(1.3		)	61.7
Income (taxes)	(37.4		)	(36.4		)	(13.7		)	(1.0		)	(22.7		)
Valencia non-controlling interest	(14.0		)	(13.6		)	(11.9		)	(0.4		)	(1.7		)
Preferred stock dividend requirements	(0.5		)	(0.5		)	(0.5		)	—			—
Segment earnings	$	54.0		$	56.8		$	19.5		$	(2.8	)	$	37.3

On August 21, 2011, PNM implemented a $72.1 million annual non-fuel rate increase for its retail customers. This rate increase, combined with a base rate increase in April 2010, improved 2012 and 2011 revenues and margins by $40.3 million and $32.1 million. In 2012, lower retail loads, primarily in the residential and commercial customer classes, reflecting lower average usage per customer and milder weather, decreased revenues and margins by $7.8 million. The increase in industrial revenue is primarily due to providing economy energy service to one customer. The only impact in margin for this customer is from minor ancillary services and other changes in revenues and cost of energy are a pass-through with no impact to margin. Higher transmission rates as a result of the June 1, 2011 rate increase, approved by FERC on January 2, 2013, also improved revenues and margins in 2012 and 2011. In 2011, increases in retail loads were primarily driven by cooler temperatures in the first quarter and warmer weather in the third quarter, improving revenue and margins by $12.0 million.

~~The~~Increases ~~table~~in ~~below~~fuel ~~summarizes~~costs and the ~~significant~~reduction ~~changes~~in off-system sales volumes resulting from the fire incident at the mine providing coal to ~~total~~SJGS ~~revenues,~~are ~~cost~~recovered ofthrough ~~energy,~~PNM's FPPAC and ~~gross~~did ~~margin:~~not negatively impact 2012 or 2011 results. See Note 16 for more discussion on the SJGS mine fire incident.

	2011/2010 Change									2010/2009 Change
	TotalRevenues			Cost ofEnergy			GrossMargin			TotalRevenues			Cost ofEnergy			GrossMargin
	(In millions)
Retail rate increases	$	32.1		$	—		$	32.1		$	40.2		$	13.2		$	27.0
Retail load, fuel, and transmission	28.3			10.7			17.5			(3.9		)	(25.9		)	22.0
Unregulated margins	(41.0		)	0.9			(41.9		)	16.6			(19.8		)	36.4
Energy efficiency rider	13.0			—			13.0			—			—			—
Net unrealized economic hedges	7.8			(1.7		)	9.5			(3.8		)	6.6			(10.4		)
Total increase (decrease)	$	40.2		$	9.9		$	30.2		$	49.1		$	(25.9	)	$	75.0

PNM implemented new rates, approved by FERC, subject to refund, for one of its firm wholesale requirements customers in April 2012, which improved revenues and margins by $4.0 million. See Note 17.

PNM offers several energy efficiency programs and initiatives to its retail customers regulated by the NMPRC. In addition, PNM is allowed to earn adders on these programs based on energy savings. PNM recovers the energy efficiency program costs via a rate rider. Revenues and margins were higher by $8.9 million and $13.0 million in 2012 and 2011, offset with an increase in operating expense for the energy efficiency program costs.

On August 20, 2012, PNM implemented its renewable energy rider, a mechanism approved by NMPRC, which will allow PNM to recover renewable energy investments, including a return on its investments, and procurement costs incurred in meeting the state-mandated RPS. See Note 17. In 2012, PNM revenues increased by $6.9 million and cost of energy, reflecting the purchase

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~~The~~cost ~~following~~of ~~table~~RECs, ~~shows~~increased ~~PNM~~$2.0 ~~Electric~~million. Included ~~operating~~in revenues is the earned return component on its investment of $1.2 million and the remaining revenues are offset by ~~customer~~increases ~~class~~in operating and ~~average~~depreciation ~~number~~expenses ofassociated ~~customers:~~with the PNM-owned PV solar facilities.

	Year Ended December 31,							Change
	2011		2010			2009		2011/2010			2010/2009
	(In millions, except customers)
Residential	$	390.4	$	355.9		$	321.0	$	34.5		$	34.9
Commercial	386.4		355.7			330.6		30.7			25.1
Industrial	94.9		85.6			79.5		9.3			6.1
Public authority	24.0		21.3			19.8		2.7			1.5
Transmission	43.6		38.7			36.1		4.9			2.6
Firm-requirements wholesale	34.1		31.9			29.0		2.2			2.9
Other sales for resale	69.3		121.7			140.3		(52.4		)	(18.6		)
Mark-to-market activity	4.2		(3.6		)	0.1		7.8			(3.7		)
Other	10.4		9.9			11.6		0.5			(1.7		)
	$	1,057.3	$	1,017.1		$	968.0	$	40.2		$	49.1
Average retail customers (thousands)	503.9		501.7			499.0		2.2			2.7

In 2012, lower unregulated revenues of $5.9 million and lower margin of $7.0 million associated with sales of power from PVNGS Unit 3 were a result of lower market power prices and increases in nuclear fuel costs. In 2011, lower unregulated revenues and margins were the result of the December 31, 2010 expiration of a long-term tolling arrangement for PVNGS Unit 3, which contained favorable pricing terms compared to 2011 market prices.

~~The~~Changes ~~following~~in ~~table~~unrealized ~~shows~~mark-to-market ~~PNM~~gains ~~Electric~~and ~~GWh~~losses are based on economic hedges for sales and fuel costs not covered under the FPPAC, primarily associated with PVNGS Unit 3. Unrealized gains of $1.6 million for 2012 compared to unrealized gains of $3.8 million for 2011 decreased margin by ~~customer~~$2.2 ~~class:~~million. Unrealized gains of $3.8 million for 2011 compared to unrealized losses of $5.7 million for 2010 increased margin by $ 9.5 million.

	Year Ended December 31,			Change
	2011	2010	2009	2011/2010		2010/2009
	(Gigawatt hours)
Residential	3,402.8	3,361.5	3,264.4	41.3		97.1
Commercial	4,043.8	4,016.0	3,899.1	27.8		116.9
Industrial	1,560.9	1,449.9	1,454.5	111.0		(4.6	)
Public authority	282.1	263.4	249.6	18.7		13.8
Firm-requirements wholesale	650.4	677.5	689.7	(27.1	)	(12.2	)
Other sales for resale	2,076.8	2,203.8	3,996.3	(127.0	)	(1,792.5	)
	12,016.8	11,972.1	13,553.6	44.7		(1,581.5	)

In 2012, operating expenses decreased by $2.1 million due to improved availability at PVNGS and $4.2 million resulting from process improvement initiatives implemented during 2011. In addition, retiree medical and employee health care costs were $1.2 million lower. These reductions in operating expenses were offset by higher expenses associated with planned maintenance outages at SJGS of $7.3 million and union labor negotiation expenses of $1.0 million. Operating expenses also increased in 2012 due to higher energy efficiency expenses and renewable expenses of $11.4 million and $1.0 million, which are offset in revenues as discussed above. As discussed in Note 7, PNM recorded a lease abandonment loss of $6.2 million in operating expenses in 2012. In addition, property taxes were higher by $2.2 million as the result of increased plant additions, higher property tax rates, and a settlement with a Native American pueblo.

~~The~~Operating ~~results~~expenses ofreflect ~~operations~~a regulatory disallowance of ~~PNM~~$17.5 ~~Electric~~million ~~are~~recorded ~~primarily~~in ~~driven~~2011 byresulting ~~the~~from ~~rate~~PNM's ~~making~~2010 ~~decisions~~Electric ~~and~~Rate ~~other~~Case. No ~~actions~~regulatory ofdisallowances ~~the~~were ~~NMPRC. On~~recorded ~~August~~in ~~21,~~2012 or in 2010. In 2011, PNM ~~implemented~~incurred aoperating expenses of $726.17 million ~~annual~~to ~~non-fuel~~implement ~~rate~~process ~~increase~~improvement ~~for~~initiatives ~~its~~related ~~retail~~to ~~customers~~reducing future costs. In addition, ~~including~~increases ~~those~~in ~~customers~~taxes ~~formerly~~other ~~served~~than byincome ~~TNMP~~due ~~(“PNM~~to ~~South”). In~~additional ~~addition,~~New ~~PNM~~Mexico ~~was~~gross ~~allowed~~receipts totax ~~implement~~on aprior ~~FPPAC~~year ~~for~~billings ~~its~~and ~~PNM~~other ~~South~~expenses ~~retail~~increased ~~customers~~operating expenses by $5. ~~This~~0 ~~rate~~million ~~increase,~~in ~~combined~~2011 ~~with~~and areduced ~~base~~operating ~~rate~~expenses ~~increase~~by $0.4 million in ~~April~~2012. Lower ~~2010,~~expense for injuries and damages improved ~~2011~~operating ~~revenues~~expenses ~~and~~in ~~margins~~2011 by $322.19 million.

~~Increases~~Depreciation inand ~~retail~~amortization ~~loads~~expense ~~were~~increased ~~primarily driven by weather~~ in ~~2011,~~2012 ~~with cooler temperatures in the first quarter~~ and ~~warmer~~2011 ~~weather~~due into ~~the~~additions ~~third~~to ~~quarter~~utility plant, ~~improving~~including ~~revenues~~PNM-owned ~~and~~solar ~~margins~~PV ~~by $12~~facilities.~~0 million.~~ ~~Higher~~Depreciation ~~transmission~~on ~~revenues~~the ~~associated with new long~~PNM-~~term~~owned ~~point~~solar toPV ~~point~~facilities ~~customers~~is ~~and~~recovered ~~the~~through ~~June 1, 2011 implementation of~~ a ~~requested~~rate ~~increase~~rider inas ~~transmission~~discussed ~~rates, which is subject to refund pending final outcome of the case, also improved revenues and margins~~above.

InFor ~~2010~~2012, ~~revenues~~other ~~and~~income ~~margins~~(deductions) ~~increased~~was ~~due~~$6.6 tomillion ~~the rate increase from PNM's 2008 Electric Rate Case~~higher, ~~which~~primarily ~~was~~related ~~implemented~~to inimproved ~~two~~performance ~~phases~~of inthe ~~July~~NDT ~~2009~~of ~~and~~$5.9 ~~April 2010~~million. ~~Retail~~PNM ~~loads~~incurred ~~improved~~less inimpairments ~~2010~~of ~~driven~~NDT ~~primarily~~investments ~~by weather impacts, as average usage per customer remained flat due~~ in ~~large~~2012 ~~part~~compared to ~~implementation~~2011. In ofaddition, ~~energy~~higher ~~efficiency~~equity ~~programs~~AFUDC ~~for~~of ~~retail customers~~$3. ~~Such~~3 ~~increases~~million ~~were~~improved ~~partially~~other income, offset by lower ~~off-system~~interest ~~sales~~income ~~volumes~~on ~~due~~the toPVNGS ~~lower~~lessor ~~available~~notes ~~excess~~of ~~generation~~$2.8 ~~from~~million ~~baseload facilities~~ due to ~~outages~~lower ~~and~~outstanding ~~increased loads~~balances. ~~These~~In ~~reductions~~2011, inlower ~~revenues,~~interest ~~along~~income ~~with~~on ~~reductions~~the inPVNGS ~~generation~~lessor ~~fuel~~notes, ~~costs~~lower ~~due~~equity toportion ~~outages~~of ~~and~~AFUDC anwere ~~increase~~partially inoffset ~~the~~with ~~volumes~~increased ~~and~~realized ~~pricing~~gains ofon ~~economy~~the ~~purchases~~NDT ~~were~~assets. A ~~offset~~pre-tax ~~through~~gain ~~the~~of ~~FPPAC~~$8.5 ~~for~~million ~~retail~~due ~~customers,~~to ~~except~~settlement ~~PNM~~of ~~South~~the ~~customers~~Republic ~~and~~Savings ~~certain~~Bank ~~wholesale~~litigation ~~customers~~increased other income in 2010.

~~Unregulated~~Interest ~~revenues~~expense increased $8.8 million and ~~margins~~$1.8 ~~are~~million ~~primarily~~in ~~from~~2012 ~~PNM's~~and ~~share~~2011 ofdue ~~PVNGS~~to ~~Unit~~the 3,issuance ~~which~~of is$160.0 ~~excluded~~million ~~from~~of ~~retail~~long-term ~~regulation~~debt in October 2011. ~~Revenues~~In ~~and~~2012, ~~margins~~the ~~decreased~~higher ~~significantly~~interest inexpense ~~2011~~was aspartially ~~long-term~~offset ~~tolling~~by ~~agreements~~$5.6 million for the ~~output~~debt portion of ~~PVNGS~~AFUDC ~~Unit~~and 3,$0.9 ~~which~~million ~~contained~~of ~~favorable~~interest ~~pricing~~charges ~~terms,~~on ~~expired~~PNM's oninvestment ~~December~~in ~~31,~~renewable ~~2010. PNM~~resources ~~hedged~~that ~~the~~are ~~output~~deferred offor ~~PVNGS~~recovery inthrough ~~2011,~~the ~~however,~~renewable energy rider.

the prices received under the 2011 agreements were significantly below those received in 2010 due to depressed market prices. PNM continues to hedge part of the output of PVNGS Unit 3 for 2012 and 2013 although market prices remain depressed.

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Unregulated revenues and margins in 2009 reflect a pre-tax charge of $32.0 million associated with a settlement arising out of certain transactions in the California energy markets during 2000 and 2001. The revenues and costs associated with Luna, Lordsburg, and the Valencia PPA were included in unregulated margins prior to May 2009, at which time these resources began to be recovered in retail rates. TNMP

~~PNM~~The ~~offers~~table ~~several~~below ~~energy~~summarizes ~~efficiency programs and initiatives to its retail customers regulated by~~ the NMPRC. In addition, PNM is allowed to earn incentives/disincentives adders on these programs, based on the energy savings of the programs. PNM recovers these energy efficiency program costs and adders via a rate rider. In 2011, revenues and margins improved by $13.0 million, of which $3.1 million is adder revenues and the remaining $9.9 million increase is offset with an increase in operating ~~expense~~results for the energy efficiency program costs. PNM expects to continue to earn incentive adder revenues based on future program participation, although the disincentive component of the adder revenues was removed upon implementation of the 2010 Electric Rate Case in August 2011. PNM is currently collecting adder revenues of $1.3 million.TNMP:

Economic hedges related to unregulated activities improved margins in 2011. Contractual positions at December 31, 2011 were favorable compared to market prices at that date. In addition, unrealized losses recorded in 2010 reversed upon settlement in 2011.



	Year Ended December 31,									Change
	2012			2011			2010			2012/2011			2011/2010
	(In millions)
Total revenues	$	250.1		$	237.9		$	212.6		$	12.2		$	25.3
Cost of energy	46.2			41.2			37.1			5.0			4.1
Margin	203.9			196.7			175.5			7.2			21.2
Operating expenses	87.1			88.2			77.4			(1.1		)	10.8
Depreciation and amortization	49.3			44.6			41.7			4.7			2.9
Operating income	67.5			63.8			56.4			3.7			7.4
Other income (deductions)	2.7			1.6			0.8			1.1			0.8
Net interest charges	(28.2		)	(29.3		)	(31.2		)	1.1			1.9
Earnings before income taxes	42.1			36.1			26.0			6.0			10.1
Income (taxes)	(15.4		)	(13.9		)	(10.0		)	(1.5		)	(3.9		)
Segment earnings	$	26.7		$	22.3		$	16.0		$	4.4		$	6.3

InThe ~~2011,~~table ~~operating~~below ~~expenses~~summarizes ~~reflect~~the ~~regulatory~~significant ~~disallowances~~changes of $17.5 million resulting from PNM's 2010 Electric Rate Case. No disallowances were recorded in 2010. Operating expenses increased associated with energy efficiency program costs of $9.9 million, which are recovered through a rate rider as discussed above. Certain process improvement initiatives to ~~reduce~~total ~~future spending of $6.7 million~~revenues, ~~renewal~~cost of ~~Native American rights-of-way at higher costs~~energy, and an increase in taxes due to New Mexico gross receipts tax on prior year billings also increased operating expenses. Lower maintenance costs at PNM's baseload generation facilities, associated with improved plant performance and timing of planned outages at SJGS, $4.6 million reduction in property insurance and injuries and damages reserves, and $4.7 million in savings in corporate allocations and overhead spending reduced operating expenses. margin:

In 2010, operating expenses increased associated with maintenance costs incurred at SJGS and Four Corners, and planned outages at PNM's gas-fired generating facilities. Renewal of Native American rights-of-way at higher costs, increases in retiree medical and pension costs, increases in allocated corporate costs, and higher property taxes further increased operating expenses, which increases were partially offset by a regulatory disallowance recorded in 2009 of $26.3 million.



	2012/2011 Change								2011/2010 Change
	Total Revenues			Cost of Energy		Margin			Total Revenues		Cost of Energy		Margin
	(In millions)
Rate increases	$	1.4		$	—	$	1.4		$	8.7	$	—	$	8.7
Customer usage/load	(2.1		)	—		(2.1		)	5.5		—		5.5
Transmission cost recovery factor	4.9			5.0		(0.1		)	6.8		4.1		2.7
AMS surcharge	6.9			—		6.9			1.6				1.6
1999 rate settlement	1.6			—		1.6			—		—		—
Other	(0.5		)	—		(0.5		)	2.7		—		2.7
Total increase	$	12.2		$	5.0	$	7.2		$	25.3	$	4.1	$	21.2

InThe ~~2011,~~following ~~depreciation~~table ~~and~~shows ~~amortization~~TNMP ~~expense~~operating ~~increased~~revenues ~~due~~by toretail ~~higher~~tariff ~~utility~~consumer ~~plant balances. In addition~~class, ~~PNM~~including ~~invested~~intersegment approximately $95 million associated with 22 MW of solar PV facilities and a solar-storage demonstration project. Incremental depreciation expense associated with these facilities is deferred to a regulatory asset pending approval of the Renewable Energy Rider. See Note 17. In 2010revenues, ~~increases in depreciation~~ and ~~amortization~~average ~~expense~~number ~~due to higher utility plant balances were offset by lower depreciation expenses on PVNGS and Reeves Station due to extension~~ of ~~their useful lives.~~ consumers:

In 2011, lower interest income associated with the scheduled pay down of the PVNGS lessor notes and a reduction in the equity portion of AFUDC lowered other income and deductions, which reductions were partially offset with increased realized gains on the NDT assets, net of fees, taxes and impairments. In 2010, other income and deductions was impacted due to a settlement received from the Republic Savings Bank litigation, which resulted in a pre-tax gain of $8.5 million. This increase was more than offset with reduced interest income associated with uncertain income tax positions compared to 2009 and lower interest associated with the scheduled pay down of the PVNGS lessor notes.



	Year Ended December 31,						Change
	2012		2011		2010		2012/2011		2011/2010
	(In millions, except customers)
Residential	$	103.3	$	100.3	$	83.6	$	3.0	$	16.7
Commercial	88.3		84.9		77.5		3.4		7.4
Industrial	13.4		13.1		12.3		0.3		0.8
Other	45.1		39.6		39.2		5.5		0.4
	$	250.1	$	237.9	$	212.6	$	12.2	$	25.3
Average consumers (thousands) ⁽¹⁾	233.0		231.3		229.4		1.7		1.9

In(1) ~~October~~TNMP ~~2011,~~provides ~~PNM~~transmission ~~issued~~and ~~$160.0~~distribution ~~million~~services ofto ~~senior~~REPs ~~unsecured notes~~ that ~~bear~~provide ~~interest~~electric atservice ~~5.35%. The~~to ~~issuance~~customers ofin ~~these~~TNMP's ~~notes~~service ~~increased~~territories. ~~interest~~The ~~charges,~~number ~~which~~of ~~increase~~consumers ~~was~~above ~~offset~~represents by the ~~deferral~~customers of ~~interest~~these ~~charges~~REPs. ~~associated~~Under ~~with~~TECA, ~~the~~consumers ~~investment~~ in ~~utility~~Texas ~~owned~~have ~~solar~~the ~~facilities~~ability asto achoose ~~regulatory~~any ~~asset. In~~REP ~~addition,~~to ~~reduced~~provide ~~interest expense from refinancing of $403~~energy.8 ~~million~~The ofaverage ~~PCRBs~~consumers inreported ~~July~~above ~~2010~~include ~~was~~67,268 ~~offset~~and by75,220 aconsumers ~~reduction in the capitalization~~ of ~~the~~TNMP ~~debt~~for ~~portion~~2011 ofand ~~AFUDC~~2010 ~~due~~that tochose ~~lower~~First ~~capitalization~~Choice ~~rates. Interest charges increased in 2010~~ as ~~lower~~their ~~capitalization~~REP. ofThese ~~interest~~consumers ~~due~~are toalso ~~reduced~~included ~~borrowing~~in ~~rates and capital expenditures more than offset lower interest on~~ the ~~refinanced~~First ~~PCRBs~~Choice segment.

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

The table below summarizes the operating results for TNMP Electric:



	Year Ended December 31,			Change
	2012	2011	2010	2012/2011		2011/2010
	(Gigawatt hours)⁽¹⁾
Residential	2,714.5	2,862.3	2,699.6	(147.8	)	162.7
Commercial	2,353.1	2,361.0	2,260.5	(7.9	)	100.5
Industrial	2,727.1	2,578.9	2,241.5	148.2		337.4
Other	103.9	108.7	103.3	(4.8	)	5.4
	7,898.6	7,910.9	7,304.9	(12.3	)	606.0

	Year Ended December 31,									Change
	2011			2010			2009			2011/2010			2010/2009
	(In millions)
Total revenues	$	237.9		$	212.6		$	192.6		$	25.3		$	20.0
Cost of energy	41.2			37.1			34.7			4.1			2.3
Gross margin	196.7			175.5			157.9			21.2			17.6
Operating expenses	88.2			77.4			75.5			10.8			1.8
Depreciation and amortization	44.6			41.7			37.3			2.9			4.5
Operating income	63.8			56.4			45.1			7.4			11.3
Other income (deductions)	1.6			0.8			2.9			0.8			(2.1		)
Net interest charges	(29.3		)	(31.2		)	(27.8		)	1.9			(3.3		)
Earnings before income taxes	36.1			26.0			20.2			10.1			5.9
Income (taxes)	(13.9		)	(10.0		)	(8.0		)	(3.9		)	(2.1		)
Segment earnings	$	22.3		$	16.0		$	12.2		$	6.3		$	3.8


⁽¹⁾	The GWh sales reported above include 836.6 and 1,012.8 GWhs for 2011 and 2010 used by consumers of TNMP who have chosen First Choice as their REP. These GWhs are also included below in the First Choice segment.

~~The~~Implementation ~~table~~of ~~below~~rate ~~summarizes~~increases in late September 2012 and February 2011 increased revenues and margins by $1.4 million in 2012. See Note 17. Higher usage per customer, after adjusting for weather impacts, and growth in the ~~significant~~number ~~changes~~of consumers in TNMP's service areas were more than offset with milder weather compared to ~~total~~2011, reducing revenues and margins by $2.1 million. In 2012, ~~cost~~TNMP received a $1.6 million settlement related to ERCOT transmission rates charged from the fourth quarter of 1999. Differences between revenues and costs charged by transmission providers are deferred and recovered through a transmission cost recovery factor, resulting in no impact to margin in 2012. On August 11, 2011, TNMP implemented a surcharge for its AMS deployment. The surcharge will recover TNMP's investment in AMS over a 12 year period. The surcharge has a true-up mechanism, which allows TNMP to match revenues collected against the expenses incurred and allows for a return to be earned on its investments. Revenues increased by $6.9 million in 2012 and $1.6 million in 2011, which offset increases in operating expenses and depreciation. Other changes in revenue include an increase for energy efficiency programs, which was more than offset by lower revenues associated with recovery of CTC, Hurricane Ike, and ~~gross~~rate ~~margin:~~case expenses.

	2011/2010 Change						2010/2009 Change
	TotalRevenues		Cost ofEnergy		GrossMargin		TotalRevenues		Cost ofEnergy		GrossMargin
	(In millions)
Rate increase	$	8.7	$	—	$	8.7	$	6.7	$	—	$	6.7
Customer growth/usage	5.5		—		5.5		4.8		—		4.8
Transmission cost recovery	6.8		4.1		2.7		—		—		—
Recovery of CTC, Hurricane Ike, energy efficiency, and other	4.3		—		4.3		8.5		2.3		6.2
Total increase	$	25.3	$	4.1	$	21.2	$	20.0	$	2.3	$	17.6

In 2011, a rate increase implemented in May 2010 increased revenues and margins by $8.7 million. In addition, weather impacts on customer usage and load, as well as moderate customer growth improved revenues and margins by $5.5 million. In 2011, changes to Texas retail electric rules that allow distribution providers to defer and recover differences between revenues and costs charged by transmission providers improved margins by $2.7 million, reflecting the elimination of the regulatory lag. Higher revenues associated with recovery of the CTC, Hurricane Ike, rate case expenses, and energy efficiency programs were offset with increases in operating expenses.

~~The~~Increases ~~following~~in ~~table~~vegetation ~~shows~~management expenses of $1.7 million, higher energy efficiency program expenses of $0.8 million, higher expenses for injuries and damages of $0.9 million, and $2.6 million higher administrative and general and customer related expenses associated with the AMS deployment increased operating expenses in 2012. As discussed in Note 7, TNMP ~~Electric~~recorded a lease abandonment loss of $1.2 million in operating ~~revenues~~expenses in 2012. These increases were offset by ~~retail~~lower ~~tariff~~maintenance ~~consumer~~expenses ~~class~~of $1.1 million related to extreme drought conditions experienced in 2011 in the Gulf Coast region, ~~including~~lower ~~intersegment~~administrative ~~revenues~~and general expenses of $1.9 million based on process improvements initiated in 2011, and ~~average~~higher ~~number~~capitalization of ~~consumers:~~administrative and general expenses related to construction projects of $1.3 million, which improved operating expenses in 2012.

	Year Ended December 31,						Change
	2011		2010		2009		2011/2010		2010/2009
	(In millions, except customers)
Residential	$	100.3	$	83.6	$	74.7	$	16.7	$	8.9
Commercial	84.9		77.5		73.3		7.4		4.2
Industrial	13.1		12.3		12.1		0.8		0.2
Other	39.6		39.2		32.5		0.4		6.7
	$	237.9	$	212.6	$	192.6	$	25.3	$	20.0
Average consumers (thousands) (1)	231.3		229.4		228.6		1.9		0.8

In 2011, operating expenses increased due to a regulatory disallowance of $3.9 million, regarding retroactive application of the interest rate used to calculate the return on TNMP's CTC regulatory assets. See Note 17. In 2011, TNMP incurred operating expenses of $1.5 million to implement process improvement initiatives related to reducing future costs. Higher allocation of corporate overhead and incentive compensation and higher street rental and property taxes, and energy efficiency and rate case amortizations also increased operating expenses in 2011.

~~(1)~~Deployment ~~Under~~of ~~TECA,~~AMS ~~consumers~~on of TNMP's ~~Electric~~system inincreased ~~Texas~~depreciation ~~have~~and ~~the~~amortization ~~ability~~by to$3.1 ~~choose~~million ~~First~~in ~~Choice or any other REP to provide energy~~2012. In ~~The~~addition, ~~average~~increased ~~consumers~~investment ~~reported~~in ~~above~~plant ~~include~~increased ~~67,268,~~depreciation ~~75,220,~~by ~~and~~$ ~~86,007~~1.8 ~~consumers~~million. In ~~of TNMP Electric for~~ 2011, ~~2010,~~depreciation and ~~2009~~amortization ~~that~~expense ~~chose~~increased ~~First~~due ~~Choice~~to ashigher ~~their~~transmission ~~REP.~~plant ~~These~~and ~~consumers are also included in~~ the ~~First~~AMS ~~Choice segment~~deployment.

An increase in contributions in aid of construction of $0.7 million and a gain on the sale of property of $0.3 million, improved other income in 2012. The refinancing of TNMP's revolving credit facility in 2010 resulted in a write-off of unamortized debt issuances costs that did not recur in 2011.

On September 30, 2011, TNMP replaced its 2009 Term Loan Agreement, at lower interest rates, which reduced interest expense in 2012 and 2011. In addition, an increase in allowance for funds used during construction further reduced interest expense in 2012. In 2010, a TNMP credit facility was amended, which resulted in lower fees and more favorable interest rates in 2011.

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

	Year Ended December 31,			Change
	2011	2010	2009	2011/2010	2010/2009
	(Gigawatt hours)(1)
Residential	2,862.3	2,699.6	2,582.6	162.7	117.0
Commercial	2,361.0	2,260.5	2,216.9	100.5	43.6
Industrial	2,578.9	2,241.5	1,983.2	337.4	258.3
Other	108.7	103.3	107.1	5.4	(3.8	)
	7,910.9	7,304.9	6,889.7	606.0	415.2

(1) The GWh sales reported above include 836.6, 1,012.8, and 1,131.9 GWhs for 2011, 2010, and 2009 used by consumers of TNMP Electric who have chosen First Choice as their REP. These GWhs are also included below in the First Choice segment.

Implementation of base rate increases in February 2011 and May 2010 increased revenues and margins by $8.7 million in 2011. Increases in consumer usage primarily associated with warmer temperatures in the second and third quarter as well as cooler temperatures in the first quarter and moderate growth in the number of consumers in TNMP's service areas also improved retail margins and revenues. Changes to Texas retail electric rules that allow distribution providers to defer and later recover or refund differences between revenues and costs charged by transmission providers improved gross margin by $2.7 million in 2011.

On August 11, 2011, TNMP implemented a surcharge for its AMS deployment. The surcharge will recover TNMP's investment in AMS over a 12 year period. The surcharge has a true-up mechanism, which allows TNMP to match revenues collected against the expenses incurred and allows for a return to be earned on its investments. In 2011, revenues increased by $1.6 million for this surcharge, which offset increases in operating expenses and depreciation. Increases in revenues associated with recovery of the CTC, Hurricane Ike, rate case expenses, and energy efficiency programs are offset with increases in operating expenses as described below.

In 2010, rate increases implemented in the third quarter of 2009 and the second quarter of May 2010 increased revenues and margins. In addition, implementation of riders for recovery of Hurricane Ike and energy efficiency programs increased revenues.

Increased maintenance activities in the Gulf coast region of TNMP's operations resulting from extreme drought conditions increased operating expenses by $1.2 million in 2011. Operating expense increases of $1.0 million in vegetation management and maintenance, $3.8 million in higher allocation of corporate overhead and incentive compensation, and higher street rental and property taxes of $0.8 million were, partially offset by a $3.0 million reduction in property insurance and injuries and damages reserves as well as higher capitalization of administrative and general expenses. In addition, increases in energy efficiency programs and rate case amortization further increased operating expenses, which are offset with revenues as described above. In 2011, operating expenses increased due to a regulatory disallowance of $3.9 million, based on a ruling in the 3rd Court of Appeals regarding retroactive application of the interest rate used to calculate the return on TNMP's CTC regulatory assets. See note 17.

In 2010, operating expenses increased due to costs associated with energy efficiency programs that are being recovered in revenues, lower capitalized overhead costs due to lower capital spending compared to 2009, and increased costs associated with the implementation of a new work management system.

Depreciation and amortization increased in 2011 related to the amortization of CTC and Hurricane Ike restoration costs. In addition, depreciation expense increased due to increases in transmission plant and the AMS deployment. In 2010, depreciation expense increased due to the amortization of Hurricane Ike restoration costs and increases in transmission plant. The refinancing of TNMP's Revolving Credit Facility in 2010 resulted in a write-off of unamortized debt issuance costs that did not recur in 2011. The recovery of carrying costs on the Hurricane Ike restoration costs recorded in 2009 increased other income and deductions in 2009.

In December 2010, the TNMP Revolving Credit Facility was amended, which resulted in lower fees and more favorable interest rates that lowered interest charges in 2011. In addition, on September 30, 2011, TNMP replaced its 2009 Term Loan Agreement, at lower interest rates, which further reduced interest expense in 2011. In 2010, interest charges increased due to higher interest rates on long-term debt issued in March 2009 and lower capitalization of interest due to reduced capital expenditures in 2010.

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Table of Contents

PNM Gas

PNM completed the sale of PNM Gas on January 30, 2009. The table below summarizes the operating results for PNM Gas, which is classified as discontinued operations in the Consolidated Statements of Earnings:

	Period from January 1 to January 30,
	2009
	(In millions)
Total revenues	$	65.7
Cost of energy	44.7
Gross margin	21.0
Operating expenses	11.3
Depreciation and amortization	—
Operating income	9.7
Other income (deductions)	0.3
Net interest charges	(1.0		)
Gain on disposal	98.4
Earnings before income taxes	107.5
Income (taxes)	(36.7		)
Segment earnings	$	70.8

First Choice

As discussed in Note 3, PNMR sold First Choice on November 1, 2011. The table below summarizes the operating results for First Choice from January 1, 2011 through October 31, 2011 compared to a full year of operations for 2010:

	Ten Months Ended October 31,			Year Ended December 31,			Change			~~Change~~
	2011			2010			~~2009~~2011/2010			~~2011/2010~~			~~2010/2009~~
	(In millions)			~~(In millions)~~
Total revenues	$	439.5		$	483.2		$	~~528~~(43.8	)	$	~~(43.8~~	)	$	~~(45.6~~	)
Cost of energy	323.3			350.5			~~346~~(27.51		)	~~(27.1~~		)	~~4.0~~
Gross margin	116.1			132.7			182.4			(16.6		)	(49.6		)
Margin	116.1			132.7			(16.6		)
Operating expenses	76.0			92.1			~~107~~(16.41		)	~~(16.1~~		)	~~(15.3~~		)
Depreciation and amortization	1.1			0.9			10.82			~~0.2~~			~~(0.9~~		)
Operating income	39.1			39.8			73(0.27		)	~~(0.7~~		)	~~(33.4~~		)
Other income (deductions)	(0.6		)	(0.4		)	(0.42		)	~~(0.2~~		)	—
Net interest charges	(0.6		)	(1.3		)	(20.87		)	~~0.7~~			~~1.5~~
Earnings before income taxes	37.9			38.1			~~70.~~(0.2		)	~~(0.2~~		)	~~(31.9~~		)
Income (taxes)	(13.8		)	(14.1		)	~~(25~~0.63		)	~~0.3~~			~~11.6~~
Segment earnings	$	24.1		$	24.1		$	440.41		$	~~0.1~~		$	~~(20.4~~	)

~~PNMR~~The ~~completed~~changes ~~the~~to ~~sale~~total ~~of First Choice on November 1~~revenues, ~~2011. As~~cost ~~a result~~ of ~~the sale~~energy, ~~the~~and ~~above~~margin ~~table~~in ~~reflects~~2011 ~~operations~~compared ofto ~~First~~2010 ~~Choice~~are ~~from~~primarily ~~January~~due 1to ~~through~~ten ~~October~~months ~~31,~~of operations in 2011, compared to atwelve ~~full~~months ~~year~~in ~~of operations for~~ 2010 ~~and 2009~~.

A-The 37following table shows First Choice operating revenues by customer class and the actual number of customers:

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	Ten Months Ended October 31,		Year Ended December 31,		Change
	2011		2010		2011/2010
	(In millions, except customers)
Residential	$	260.2	$	305.8	$	(45.6	)
Commercial	166.5		159.8		6.7
Other	12.8		17.6		(4.9		)
	$	439.5	$	483.2	$	(43.8	)
Actual customers (thousands) ^(1,2)	221.1		214.2		6.9

~~The~~(1) ~~changes~~See tonote ~~total~~above ~~revenues, cost of energy, and gross margin~~ in ~~2011~~the ~~compared~~TNMP tosegment ~~2010~~discussion ~~are~~about ~~primarily due to ten months of operations in 2011 compared to twelve months in 2010. The following table summarizes~~ the ~~significant~~impact ~~changes to total revenues, cost~~ of ~~energy, and gross margin for 2010 compared to 2009:~~TECA.

	2010/2009 Change
	TotalRevenues			Cost ofEnergy			GrossMargin
	(In millions)
Weather	$	11.6		$	7.4		$	4.2
Customer growth/usage	(15.6		)	(12.8		)	(2.8		)
Retail margins	(41.6		)	(19.1		)	(22.5		)
Unrealized economic hedges	—			28.5			(28.5		)
Total increase (decrease)	$	(45.6	)	$	4.0		$	(49.6	)


⁽²⁾	Due to the competitive nature of First Choice’s business, actual customer count at the end of the period is a more representative business indicator than average customers.

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

	Ten Months Ended October 31,		Year Ended December 31,				Change
	2011		2010		2009		2011/2010			2010/2009
	(In millions, except customers)
Residential	$	260.2	$	305.8	$	349.6	$	(45.6	)	$	(43.8	)
Commercial	166.5		159.8		161.0		6.7			(1.2		)
Other	12.8		17.6		18.2		(4.9		)	(0.6		)
	$	439.5	$	483.2	$	528.8	$	(43.8	)	$	(45.6	)
Actual customers (thousands) (1,2)	221.1		214.2		225.0		6.9			(10.8		)

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

(2) Due to the competitive nature of First Choice’s business, actual customer count at the end of the period is 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:

	Ten Months Ended October 31,	Year Ended December 31,	Change		~~Change~~
	2011	2010	~~2009~~2011/2010		~~2011/2010~~		~~2010/2009~~
	(Gigawatt hours(1))
Residential	2,006.4	2,267.8	~~2,441~~(261.64	)	~~(261.4~~	)	~~(173.8~~	)
Commercial	1,538.2	1,363.8	~~1,218~~174.94		~~174.4~~		~~144.9~~
	3,544.6	3,631.6	~~3,660~~(87.50	)	~~(87.0~~	)	~~(28.9~~	)

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

~~Total~~A- revenues decreased in 2011, primarily due to the ten months of operations in 2011 versus twelve months in 2010. Prior to the sale, total revenues increased in 2011 compared to the same period in 2010 due to favorable weather and an increase in both MWh sales and number of customers, which were partially offset by a decrease in the average revenue rates. First Choice incurred significantly higher purchased power costs per MWh due to extreme summer temperatures in 2011. These higher energy costs more than offset the increase in revenues. During 2010, a decrease in average revenue rates, lower MWh sales, and a reduction in the number of customers resulted in decreased operating revenue when compared to 2009. The decrease in 2010 was partially offset by lower purchased power costs and favorable weather but overall resulted in decreased gross margin. 36

First Choice managed its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins. Accordingly, First Choice had forward contracts for the purchase of energy

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Total revenues decreased in 2011, primarily due to ~~cover~~the ten months of operations in 2011 versus twelve months in 2010. Prior to the ~~future~~sale, ~~load~~total ~~requirements~~revenues ~~for~~increased ~~most~~in of2011 ~~its~~compared ~~fixed~~to ~~price~~the same period in 2010 due to favorable weather and an increase in both MWh sales ~~contracts~~and number of customers, which were partially offset by a decrease in the average revenue rates. ~~Gains~~First orChoice ~~losses~~incurred onsignificantly ~~unrealized~~higher ~~economic~~purchased ~~hedges~~power ~~represent~~costs ~~changes~~per MWh due to extreme summer temperatures in ~~unrealized~~2011. These ~~fair~~higher ~~value~~energy ~~estimates~~costs ~~related~~more than offset the increase in revenues. First Choice managed its exposure to ~~these~~fluctuations ~~forward~~in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins. Accordingly, First Choice had forward contracts for the purchase of energy to cover the future load requirements for most of its fixed price sales contracts. Changes in the fair value of supply contracts that were not designated or were not eligible for hedge or normal purchase or sales accounting were marked to market through current period earnings as required by GAAP. During 2010, market energy prices decreased significantly, which resulted in GAAP losses on certain of First Choice's forward supply contracts. During 2011, market energy prices increased, which resulted in unrealized mark-to-market gains on certain of First Choice's forward supply contracts. First Choice was not required to mark the related fixed price sales contracts to market, which would likely offset the supply contracts. Gains on unrealized economic hedges increased segment earnings by $4.9 million in 2011 compared with losses of $22.4 million in 2010 ~~and gains of $6~~.~~1 million in 2009.~~

The allowance for uncollectible accounts and related bad debt expense was based on collections and write-off experience. InBad ~~2009,~~debt ~~the~~expense ~~customer~~decreased ~~default~~$16.2 ~~rates~~million ~~experienced~~in ~~were~~2010 ~~significantly above historic levels~~ due to ~~overall economic conditions, higher average final bills, and an increase in customer churn. Since 2009,~~ lower customer departures, lower default rates, and an increase in commercial customers ~~have reduced bad debts~~. ~~As a result, bad debt expense decreased in 2010, which increased segment earnings, by $16.2 million.~~ In 2011, bad debt expense decreased by $4.6 million, primarily due to the ten months of operations in 2011 versus twelve months in 2010. Initiatives to reduce bad debts included 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 focused its marketing efforts on commercial customers and customers with established payment patterns~~. First~~, ~~Choice also~~ increased the ~~credit score~~ required tocredit ~~become a customer~~ score, and expanded ~~the circumstances where customers are required to provide~~ advance deposits ~~to obtain service, or both~~requirements. In September 2010, the PUCT adopted a switch/hold provision for customer accounts on a deferred payment plan, an average payment plan, or with a meter determined to have been tampered with, which will require those customers to pay any outstanding balance before changing to another REP. The switch/hold provision became effective on June 1, 2011.

Total operating expenses decreased in 2011, primarily due to the ten months of operations in 2011 versus twelve months in 2010. Prior to the sale, operating expenses in 2011 increased compared to the same period in 2010 due to increases in marketing and operational costs which were partially offset by a decrease in incentive compensation expense. In 2010, First Choice incurred increased operational costs compared to 2009, which included expenses related to opening several local office locations as well as support expenses. This increase was partially offset by lower customer acquisition expenses when compared to 2009. In 2011 and 2010, interest expense decreased primarily due to lower short-term debt.

Corporate and Other

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

	Year Ended December 31,									Change
	2011			2010			2009			2011/2010			2010/2009
	2012			2011			2010			2012/2011			2011/2010
				(In millions)
Total revenues	$	~~(34.0~~—	)	$	(3934.40	)	$	(4139.74	)	$	534.40		$	25.34
Cost of energy	~~(33.8~~—		)	(3933.18		)	(4139.31		)	533.38			25.3
Gross margin	(0.2		)	(0.3		)	(0.4		)	0.2			0.1
Margin	—			(0.2		)	(0.3		)	0.2			0.2
Operating expenses	(917.79		)	(129.37		)	(1312.53		)	2(8.62		)	1.2.6
Depreciation and amortization	1617.5			16.85			16.78			(01.30		)	(0.13		)
Operating income (loss)	~~(7.~~0.3		)	(47.90		)	(34.69		)	(27.23		)	(12.32		)
Gain on sale of First Choice	~~174~~1.90			—174.9			—			~~174~~(173.9		)	—174.9
Optim Energy loss and impairment	—			~~(203.4~~—		)	(30203.14		)	~~203.4~~—			~~(173~~203.34		)
Other income (deductions)	(~~15.~~8.1		)	(615.08		)	15(6.20		)	(97.87		)	(219.28		)
Net interest charges	(1916.6		)	(2019.56		)	(2220.5		)	03.90			2.0.9
Earnings (loss) before income taxes	~~132~~(23.54		)	~~(234~~132.85		)	(41234.18		)	~~367~~(155.39		)	~~(193~~367.83		)
Income (taxes) benefit	~~(56~~11.52		)	92(56.85		)	1892.58			~~(149~~67.37		)	74(149.3		)
Segment earnings (loss)	$	76(12.02	)	$	~~(142~~76.0	)	$	(22142.50	)	$	~~218~~(88.12	)	$	~~(119~~218.51	)

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 services to First Choice prior to November 1, 2011, when PNMR sold First Choice. Accordingly, there was no elimination of intersegment revenue in 2012.

A-Operating 39expenses decreased in 2012 and increased in 2011 primarily due to legal and consulting expenses of $4.6 million incurred in 2011 related to assessment of strategic alternatives for PNMR's competitive businesses. Other changes in operating

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Table of Contents

~~Operating~~ expenses ~~increased~~are ~~$1.2~~offset ~~million~~as ina ~~2010~~result ~~and~~of ~~$2.6~~allocation ~~million~~of indepreciation ~~2011. The~~and ~~increase~~amortization ~~in 2011 is primarily due to legal~~ and ~~consulting~~items ~~expenses~~within ~~incurred~~other ~~related~~income to(deductions) ~~assessments of strategic alternatives for PNMR's competitive businesses. The increase in 2010 was driven primarily by a fee that was received from NMGC in 2009 related~~ to ~~the~~other ~~transition~~business ~~of accounting systems following the sale of PNM Gas~~segments.

~~Corporate~~Depreciation ~~and~~expense ~~Other~~increased ~~results~~in ~~include~~2012 adue ~~gain~~to onaccelerated ~~the~~amortization ~~sale~~of leasehold improvements for part of ~~First~~its ~~Choice~~corporate headquarters that was abandoned during 2012. ~~Results~~This increase was partially offset by lower depreciation on software applications compared to 2011. Changes in depreciation and amortization are offset in operating expenses as a result of ~~operations~~allocation of ~~First~~these ~~Choice~~costs ~~are~~to ~~discussed~~other ~~above~~business segments. ~~The~~PNM ~~sale~~and TNMP defer their allocations of ~~First~~the ~~Choice~~accelerated isamortization ~~discussed~~of inleasehold ~~Note~~improvements 2as regulatory assets to be recovered through rates.

Corporate and Other results ~~also~~ include ~~losses~~the ~~associated~~gain ~~with~~on ~~Optim~~the ~~Energy. Further~~sale ~~information~~of ~~regarding~~First ~~Optim Energy is shown below~~Choice. ~~The~~Results ~~loss~~of ~~due~~operations ~~to the impairment~~ of ~~PNMR's~~First ~~investment~~Choice inare ~~Optim Energy, which is~~ discussed above. The ~~and~~sale inof ~~Note~~First ~~21,~~Choice is ~~also~~discussed ~~reflected~~ in ~~the~~Note ~~Corporate and Other segment~~3.

~~Other~~Corporate ~~income~~ and ~~deductions~~Other ~~decreased~~results inalso ~~2011~~include ~~primarily~~losses ~~due~~associated towith aOptim $9Energy.2 Further ~~million~~information ~~loss~~regarding onOptim ~~the~~Energy ~~repurchase~~is ofshown ~~$50~~below.~~0 million of PNMR's 9.25% senior unsecured notes (Note 6).~~ ~~Other~~The ~~income and deductions decreased in~~ 2010 ~~compared~~loss ~~to 2009 primarily~~ due to athe ~~$15.0~~impairment ~~million~~of ~~fee~~PNMR's ~~received~~investment ~~upon~~in ~~termination~~Optim ofEnergy, ~~the~~which ~~CRHC~~is ~~acquisition~~discussed ~~agreement~~above and ain ~~gain~~Note of21, ~~$7.3~~is ~~million~~also onreflected in the ~~repurchase~~Corporate ofand ~~$157.4~~Other ~~million of PNMR's 9~~segment.~~25% senior unsecured notes, both of which occurred in 2009.~~

~~Net~~Other ~~interest~~income ~~charges~~and deductions decreased byin ~~$2.0~~2011 ~~million~~and increased in ~~2010~~2012 ~~and~~primarily due to a $0.9.2 million inloss ~~2011. The~~on ~~decrease~~the inrepurchase ~~2011~~of ~~compared~~$50.0 tomillion ~~2010~~of isPNMR's ~~primarily~~9.25% ~~related~~senior tounsecured ~~lower~~notes ~~borrowings~~in ofNovember ~~long-term~~2011 ~~debt~~(Note 6). ~~The~~This ~~decrease~~was inoffset ~~2010~~by islower ~~primarily~~performance ~~related~~on toother ~~lower~~investments. Net ~~borrowings~~interest ofcharges ~~long-term~~decreased ~~debt~~in 2012 and ~~interest~~2011, onprimarily ~~uncertain~~due ~~income~~to ~~tax~~the ~~positions~~re-acquisition.

In 2010 and 2012, income tax benefit was reduced by $2.6 million and $0.7 million due to the impairment of New Mexico wind energy production tax credit carry forwards. These credits were not expected to be utilized prior to their expiration due to the Company's net operating loss position. On January 3, 2013, the American Taxpayer Relief Act of 2012, which extended fifty percent bonus depreciation, was signed into law. Due to provisions in the act, taxes payable to the state of New Mexico for 2013 will be reduced and PNMR anticipates that it will be required to impair an additional $1.5 million of New Mexico wind energy production tax credits in the first quarter of 2013.

Optim Energy

As described above and in Note 21, PNMR reduced its investment in Optim Energy to zero at December 31, 2010 due to the determination that the investment was fully impaired, resulting in a pre-tax impairment loss of $188.2 million ($113.7 million after-tax). In accordance with GAAP, PNMR did not record income or losses associated with its investment in Optim Energy in 2011 as PNMR had no contractual requirement or agreement to provide Optim Energy with additional financial resources. Accordingly, Optim Energy ~~has~~had no impact on PNMR's 2011 balance sheet, statement of earnings, and statement of cash flows. ~~Therefore,~~Summarized ~~summarized~~ financial information for Optim Energy is not presented ~~for 2011~~. PNMR entered into agreements on September 23, 2011 that reduced PNMR's ownership in Optim Energy from 50% to 1%. On January 4, 2012, ECJV exercised its option to acquire PNMR's remaining 1% ownership interest in Optim Energy at fair market value, which was determined to be zero. PNMR accounted for its investment in Optim Energy using the equity method of accounting until September 23, 2011 and used the cost method thereafter.

In ~~2009 and~~ 2010, Optim Energy's strategy and near-term focus was on utilizing cash flow from operations to reduce debt and optimizing its generation assets as a stand-alone independent power producer. Optim Energy's results of operations were primarily determined by the prices at which its power was sold and its fuel to generate power, principally natural gas, was procured. Power prices in the ERCOT market are directly correlated to natural gas prices. The markets for power and natural gas were depressed in ~~2009 and~~ 2010. Optim Energy had net earnings (loss) of $(25.1) million ~~and~~for ~~$(56.8) million in~~ the ~~years~~year ended December 31, 2010 ~~and 2009~~. PNMR recognized net earnings (loss) from Optim Energy of $(15.2) million ~~and~~for ~~$(30.1) million in~~ the ~~years~~year ended December 31, 2010 ~~and 2009~~. Such amounts include amortization of a basis difference between PNMR's recorded investment in Optim Energy and 50 percent of Optim Energy's equity.

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Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The information concerning PNMR’s cash flows is summarized as follows:

	Year Ended December 31,									Change
	2011			2010			2009			2011/2010			2010/2009
	2012			2011			2010			2012/2011			2011/2010
	(In millions)
Net cash flows from:
Operating activities	$	~~292~~281.23		$	~~287~~292.42		$	87287.74		$	4(10.89	)	$	~~199~~4.78
Investing activities	19(285.89		)	~~(275~~19.98		)	~~379~~(275.79		)	~~295~~(305.7		)	~~(655~~295.67		)
Financing activities	(~~312~~1.36		)	(10312.73		)	(~~593~~10.47		)	~~(301~~310.67		)	~~582~~(301.76		)
Net change in cash and cash equivalents	$	(06.31	)	$	(0.83	)	$	~~(126.~~0.8	)	$	(15.19	)	$	~~126~~(1.81	)

The changes in PNMR's cash flows from operating activities relate primarily to ~~increased~~improved ~~cash~~results ~~flows~~of operations at PNM and TNMP, primarily due to rate increases, inas ~~2011~~well ~~and~~as ~~2010~~PNM's ~~and~~receipt aof ~~reduction~~$21.6 million for governmental grants related to renewable energy initiatives in ~~collateral~~2012 ~~requirements~~compared atto ~~December~~$2.1 ~~31,~~million in 2011,. Increases ~~primarily~~were ~~due~~mostly offset by gains related to the sale of First Choice~~. Net~~ ~~refunds~~ of ~~income taxes of~~ $51.50 million ~~and~~in 2012 compared to $99174.39 million in 2011. Contributions to the PNM and ~~2010~~TNMP ~~compared~~pension ~~with~~and ~~net~~other ~~payments~~postretirement benefit plans of $~~118~~89.2 million in ~~2009~~2012 ~~also~~compared ~~contributed~~ to ~~the changes~~$48. ~~The~~3 ~~net~~million ~~refund~~in of2011 and income taxes inpaid ~~2010~~of ~~included~~$5.3 ~~changes~~million in ~~book~~2012 compared to ~~tax~~refunds ~~differences~~of on$5.5 ~~capitalized~~million ~~overheads~~in 2011 and in$99.3 ~~2009~~million ~~was~~in ~~primarily~~2010 ~~related~~also tooffset the ~~sale of PNM Gas~~increases.

The changes in PNMR's cash flows from investing activities relate primarily to ~~the~~ proceeds from the sale of First Choice of $4.0 in ~~2011~~2012 ofcompared to $329.3 million ~~and~~offset by related transaction costs of $10.9 million in 2011. Utility plant additions decreased $618.50 million in ~~2010~~2012 and increased $45.4 million in 2011. At ~~after~~PNM, ~~reflecting~~total ~~payments~~utility ~~for~~plant ~~rights-of-way~~additions ~~renewals~~in at2012 decreased by $54.5 million and increased by $45.4 million in 2011. PNM's of2011 additions included $1159.2 million related to solar projects, which were completed by the end of 2011. TNMP utility plant additions increased $25.6 million in 2012 compared to 2011, including increases of $2912.39 million in ~~2010~~distribution projects, $13.8 million in transmission projects, and a decrease of $102.68 million inrelated ~~2009~~to the deployment of advanced meters. InPlant ~~addition,~~additions ~~PNMR~~at ~~made~~the ~~equity~~Corporate ~~contributions~~and ofOther segment also increased $2013.34 million in 2012 primarily related to ~~Optim~~improvements ~~Energy~~to inthe ~~2010~~Company's corporate headquarters building. Construction expenditures were funded primarily through cash flows from operating activities and short-term borrowings. In ~~2009~~addition, ~~PNM~~PNMR ~~received~~made ~~proceeds~~equity contributions of $~~652~~20.93 million ~~from~~to ~~the~~Optim ~~sale~~Energy ofin ~~PNM Gas~~2010.

The changes in cash flows from financing activities relate primarily to the use of ~~the~~ proceeds from the sale of First Choice in 2011 to purchase PNMR common stock for $125.7 million, PNMR's convertible preferred stock, Series A, for $73.5 million, and long-term debt for $58.5 million. In ~~addition~~2012, ~~payments~~PNMR ~~received~~obtained ~~on PVNGS firm-sales contract arrangements were~~ $2100.60 million in ~~2011,~~new ~~compared~~short-term toborrowings, ~~$30.5 million in 2010~~ and ~~$30.7~~used ~~million~~the inproceeds ~~2009,~~to asrepay ~~those~~borrowings ~~contracts~~under ~~expired~~the atPNMR ~~December~~Revolving ~~31,~~Credit ~~2010~~Facility. AIn ~~net~~2012, ~~repayment~~PNM ofrefinanced $320.40 million ~~for transmission interconnection arrangements at PNM in 2011 compared to proceeds~~ of $8PCRBs.~~5 million in 2010 also contributed to the change.~~ In 2011, PNM obtained $160.0 million in new long-term borrowings, using the proceeds to reduce short-term borrowings. Also in 2011, TNMP replaced $50.0 million in long-term debt with a new term loan agreement for $50.0 million. In ~~2010~~addition, ~~PNM~~payments ~~refinanced~~received ~~the~~on ~~$403.8~~PVNGS ~~million~~firm-sales ofcontract ~~PCRBs. In~~arrangements ~~2009,~~were ~~the~~$2.6 ~~proceeds~~million ~~from~~in ~~the~~2011 ~~sale~~compared ofto ~~PNM~~$30.5 ~~Gas~~million ~~were~~in ~~used~~2010 toas ~~retire~~those ~~short-term~~contract ~~borrowings~~expired at ~~PNM~~December ~~and PNMR~~31, ~~as well as the retirement of long-term borrowings at PNMR~~2010. AtIn ~~TNMP~~2010, ~~the~~PNM ~~retirement~~refinanced ofthe ~~both~~$403.8 ~~short-term~~million ~~and~~of ~~long-term borrowings was financed by new long-term borrowings in 2009~~PCRBs.

Financing Activities

See Note 6, for additional information concerning the Company’s financing activities. In May 2012, PNM received NMPRC approval to participate in the refunding of $20.0 million of PCRBs. PNM also received NMPRC authority to exercise the two one-year extension options under the PNM Revolving Credit Facility. The PNMR Revolving Credit Facility also provides for two one-year extension options although NMPRC authority to exercise them is not required. In October 2012, the first of the one-year extension options for the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility were exercised extending the expiration of both facilities to October 31, 2017.

In September 2012, PNM participated in the issuance of $20.0 million of new PCRBs by the City of Farmington, New Mexico, which bear interest at 2.54% and mature September 1, 2042 with a mandatory tender on June 1, 2017. The new PCBRs refunded a $20.0 million series of PCRBs, which bore interest at 5.15% and matured in 2037, that were redeemed at par and retired.

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Table of Contents

Capital Requirements

Total capital requirements consist of construction expenditures and cash dividend requirements for PNMR common stock and PNM preferred stock. Key activities in PNMR's current construction program include:


•	Upgrading generation resources, including those for renewable energy


•	Expanding the electric transmission and distribution systems


•	Purchasing nuclear fuel

Projected capital requirements for 2013-2017 are:

	2012		2013-2016		Total
	2013		2014-2017		Total
	(In millions)
Construction expenditures	$	~~286~~372.68	$	1,~~020~~409.31	$	1,~~306~~781.9
Dividends on PNMR common stock	4652.26		~~184~~210.83		~~231~~262.09
Dividends on PNM preferred stock	0.5		2.01		2.56
Total capital requirements	$425.9	~~333.3~~	$1,621.5	~~1,207.1~~	$2,047.4	~~1,540.4~~

A-The 41construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above include additional renewable resources anticipated to be required to meet the RPS, additional peaking resources needed to meet needs outlined in PNM's current IRP, and environmental upgrades at Four Corners of $71.9 million estimated to be expended through 2017. The construction expenditures above do not include any amounts related to environmental upgrades at SJGS that ultimately may be required by EPA to address regional haze or expenditures that could be required to replace capacity should environmental control at SJGS involve shutdown of one or more SJGS units. See Note 16 and Commitments and Contractual Obligations below. The ability of PNMR to pay dividends on its common stock is dependent upon the ability of PNM and TNMP to be able to pay dividends to PNMR. Note 5 describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP.

~~Table~~During ofthe ~~Contents~~year ended December 31, 2012, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements.

The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above do not include any amounts related to environmental upgrades at SJGS or Four Corners that may be required by EPA to address regional haze, additional renewable resources that may be required to meet the RPS, or additional peaking resources that may be needed to meet needs outlined in PNM's current IRP. Estimates for construction expenditures currently do not include any significant expenditures for environmental control facilities. See Note 16 and Commitments and Contractual Obligations below. The ability of PNMR to pay dividends on its common stock is dependent upon the ability of PNM and TNMP to be able to pay dividends to PNMR. Note 5 describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP.

During the year ended December 31, 2011, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements.

In addition to the capital requirements for construction expenditures and dividends, the Company has long-term debt that must be paid or refinanced at maturity. Note 6 contains information about the maturities on long-term debt. The Company has from time to time refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, the Company may refinance other debt issuances or make additional debt repurchases in the future.

Liquidity

PNMR's liquidity arrangements include the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility that both expire in ~~2016~~October 2017 and the TNMP Revolving Credit Facility that expires in December 2015. On October 31, 2011, PNMR entered into the PNMR Revolving Credit Facility, which has a financing capacity of $300.0 million, and PNM entered into the PNM Revolving Credit Facility, which has a financing capacity of $400.0 million. The new credit facilities ~~replace~~replaced ~~the~~existing ~~PNMR Facility and the PNM Facility, both of which would have expired in August 2012~~facilities. The terms and conditions of the new facilities are substantially similar to the prior facilities and the Company believes the terms and conditions are consistent with those of other investment grade revolving credit facilities in the utility industry. ~~Each~~On ofDecember 14, 2012, PNMR entered into the ~~new~~PNMR Term Loan Agreement. On December 27, 2012, PNMR borrowed $100.0 million under the PNMR Term Loan Agreement and used the funds to repay $100.0 million in borrowings made under the PNMR Revolving Credit Facility. Each of these facilities contains one financial covenant that requires the maintenance of debt-to-capital ratios of less than or equal to 65%. These ratios reflect the present value of payments under the PVNGS and EIP leases as debt.

~~These~~The revolving credit facilities provide short-term borrowing capacity and also allow letters of credit to be issued. Letters of credit reduce the available capacity under the facilities. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. The Company's business is seasonal with more revenues and cash flows from operations being generated in the summer months. In general, the Company relies on the credit facilities to be the initial funding source for construction expenditures. Accordingly, borrowings under the facilities increase over time. Depending on market and other conditions, the Company will periodically sell long-term debt and use the proceeds to reduce the borrowings under the credit facilities. Short-term borrowings at PNMR ranged from ~~zero~~$14.0 million to $~~106~~141.0 million during the year ended December 31, ~~2011~~2012 and from $101.0 million to $129.0 million during the three months ended December 31, ~~2011~~2012. PNM short-term borrowings ranged from zero to $~~298~~168.0 million during the year ended December 31, ~~2011~~2012 and from zero to $~~257~~35.0 million during the three months ended December 31, ~~2011~~2012. PNMR short-term borrowings ranged from ~~$14.0~~zero ~~million~~ to $~~133~~106.0 million during the year ended December 31, ~~2010~~2011. PNM short-term borrowings ranged from ~~$110.0~~zero ~~million~~ to $~~244~~298.0 million during the year ended December 31, 2010. There were no borrowings under the TNMP Revolving Credit Facility during 2011 and 2010. At December 31, 2011, average interest rates were 2.05% for the PNMR Revolving Credit Facility and 1.80% for the PNM Revolving Credit Facility. PNMR also has a $5.0 million line of credit expiring in August 2012 with a single financial institution.

The Company currently believes that its capital requirements can be met through internal cash generation, existing credit arrangements, and access to public and private capital markets. To cover the difference in the amounts and timing of internal cash generation and cash requirements, the Company intends to use shortA-~~term~~ borrowings under its current and future liquidity arrangements. However, if difficult market conditions experienced during the recent recession return or worsen, the Company may not be able to access the capital markets or renew credit facilities when they expire. Should that occur, the Company would seek to improve cash flows by reducing capital expenditures and exploring other available alternatives. Also, PNM may consider seeking authorization for the issuance of first mortgage bonds to improve access to the capital markets.40

InTable ~~addition~~of toContents its internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing to fund its capital requirements during the 2012-2016 period. This could include debt refinancing, new debt issuances, and/or new equity.

December 31, 2011. There were no borrowings under the TNMP Revolving Credit Facility during 2012 and 2011. At December 31, 2012, average interest rates were 1.96% for the PNMR Revolving Credit Facility, 1.335% for the PNMR Term Loan Agreement, and 1.71% for the PNM Revolving Credit Facility.

The Company currently believes that its capital requirements can be met through internal cash generation, existing credit arrangements, and access to public and private capital markets. To cover the difference in the amounts and timing of internal cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements. However, if difficult market conditions experienced during the recent recession return, the Company may not be able to access the capital markets or renew credit facilities when they expire. Should that occur, the Company would seek to improve cash flows by reducing capital expenditures and exploring other available alternatives. Also, PNM may consider seeking authorization for the issuance of first mortgage bonds to improve access to the capital markets.

In addition to its internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing to fund its capital requirements during the 2013-2017 period. This could include debt refinancing, new debt issuances, and/or new equity.

The Company's ability to access the credit and capital markets at a reasonable cost is largely dependent upon its:


•	Ability to earn a fair return on equity


•	Results of operations


•	Ability to obtain required regulatory approvals

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•	Conditions in the financial markets


•	Credit ratings

On ~~September~~April 2613, ~~2011~~2012, S&P raised the corporate credit ~~ratings~~rating for PNMR, ~~PNM,~~as ~~and~~well ~~TNMP~~as ~~and~~the ~~changed~~senior ~~the~~debt ~~outlook~~ratings for ~~each~~PNMR ~~entity~~and toTNMP ~~positive. On~~and ~~November 1, 2011, Moody's raised~~ the ~~credit~~preferred ~~ratings~~stock rating for ~~PNMR~~PNM. S&P ~~and~~changed ~~TNMP but retained~~ the outlook atto stable for all entities. As of February 22, ~~2012~~2013, ratings on the Company's debt securities were as follows:

	PNMR	PNM	TNMP
S&P
Senior secured	*	*	BBB+
Senior unsecured	BB+	BBB-	*
Preferred stock	*	B+BB	*
Moody’s
Senior secured	*	*	A3
Senior unsecured	Ba1	Baa3	*
Preferred stock	*	Ba2	*
* Not applicable

Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it is subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.

A summary of liquidity arrangements, which do not include the PNMR Term Loan Agreement, as of February 22, ~~2012~~2013 is as follows:

	PNMRSeparate		PNMSeparate		TNMPSeparate		PNMRConsolidated
			(In millions)
Financing Capacity:
Financing capacity - revolving credit facility	$	300.0	$	400.0	$	75.0	$	775.0
Revolving credit facility	$	300.0	$	400.0	$	75.0	$	775.0
Amounts outstanding as of February 22, 2013:
Local lines of credit	5.0		—		—		5.0
Revolving credit facility	24.2		107.7		25.0		156.9
Total financing capacity	$	305.0	$	400.0	$	75.0	$	780.0
Letters of credit	11.3		3.5		0.3		15.1
Amounts outstanding as of February 22, 2012:
Total short term-debt and letters of credit	35.5		111.2		25.3		172.0
Revolving credit facility	$	27.8	$	152.3	$	—	$	180.1
Remaining availability as of February 22, 2013	$	264.5	$	288.8	$	49.7	$	603.0
Local lines of credit	—		—		—		—
Invested cash as of February 22, 2013	$	2.8	$	—	$	—	$	2.8
Total short-term debt outstanding	27.8		152.3		—		180.1
Letters of credit	11.0		3.7		0.3		15.0
Total short term-debt and letters of credit	$	38.8	$	156.0	$	0.3	$	195.1
Remaining availability as of February 22, 2012	$	266.2	$	244.0	$	74.7	$	584.9
Invested cash as of February 22, 2012	$	0.6	$	—	$	—	$	0.6

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The above table excludes intercompany debt. The remaining availability under the revolving credit facilities at any point in time varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures.

For offerings of securities registered with the SEC, PNMR has a shelf registration statement expiring in March 2014. This shelf registration statement has unlimited availability and can be amended to include additional securities, subject to certain restrictions and limitations. PNMR can also offer new shares of common stock through the PNM Resources Direct Plan under a separate SEC shelf registration statement that expires in August ~~2012~~2015. PNM has a shelf registration statement for up to $440.0 million of senior unsecured notes that will expire in May 2014.

Off-Balance Sheet Arrangements

PNMR's off-balance sheet arrangements include PNM's operating lease obligations for PVNGS Units 1 and 2, the EIP transmission line, and Delta.

AIn 1985 and 1986, PNM consummated sale and leaseback transactions for its interest in PVNGS Units 1 and 2. The original purpose of the sale-leaseback 43financing was to lower revenue requirements and to levelize the ratemaking impact of PVNGS being placed in-service. The lease payments reflected lower capital costs as the equity investors were able to capitalize the investment with greater leverage than PNM and because the sale transferred tax benefits that PNM could not fully utilize. Under traditional ratemaking, the capital costs of ownership of a major rate base addition, such as a nuclear plant, are front-end loaded. The revenue requirements are high in the initial years and decline over the life of the plant as depreciation occurs. By contrast, the lease payments are level over the lease term. The leases, which expire in 2015 and 2016, contain options to renew the leases at a fixed price or to purchase the property for fair market value. See discussion below and Note 7 regarding the status of these alternatives.

~~Table~~Additionally, in 1996, PNM entered into a PPA for the rights to all the output of ~~Contents~~the Delta generating plant through June 2020. The PPA is accounted for as an operating lease. The gas turbine generating unit is operated by Delta, which is a variable interest entity. The plant is mainly used to meet peak load requirements. See Note 9 for additional information about the Delta operating lease, including the potential purchase of Delta.

InFor ~~1985~~reasons ~~and~~similar ~~1986,~~to ~~PNM~~the ~~consummated~~PVNGS sale and leaseback transactions, ~~for~~PNM ~~its~~built ~~interest~~the inEIP ~~PVNGS~~Transmission ~~Units~~Line 1 and ~~2. The~~sold ~~original~~it ~~purpose~~in ~~of the~~ sale~~-leaseback~~ ~~financing was to lower revenue requirements~~ and toleaseback ~~levelize~~transactions ~~the ratemaking impact of PVNGS being placed~~ in~~-service~~ 1985. The ~~lease~~EIP ~~payments~~line ~~reflected~~is ~~lower~~a ~~capital~~216 ~~costs~~mile, as345 ~~the~~kilovolt ~~equity~~line ~~investors~~with ~~were~~a ~~able~~capacity toof ~~capitalize~~200 ~~the~~MW. PNM ~~investment~~currently ~~with~~owns ~~greater~~60% ~~leverage than PNM~~ and ~~because~~operates the ~~sale~~other ~~transferred~~40% ~~tax~~of ~~benefits~~the ~~that~~EIP ~~PNM~~line ~~could~~under ~~not fully utilize. Under traditional ratemaking,~~ the ~~capital~~terms ~~costs~~ of ~~ownership of~~ a ~~major~~lease ~~rate base addition, such as a nuclear plant, are front-end loaded~~agreement. The ~~revenue~~lease ~~requirements~~expires ~~are high~~ in ~~the~~2015 ~~initial~~with ~~years~~fixed-rate and ~~decline~~fair ~~over~~market ~~the~~value ~~life~~renewal ofoptions ~~the~~and ~~plant~~a asfair ~~depreciation~~market ~~occurs. By~~value ~~contrast,~~purchase ~~the lease payments are level over the lease term~~option. ~~The~~PNM ~~leases,~~has ~~which~~agreed ~~expire~~to inexercise ~~2015~~its ~~and 2016, contain options~~ option to ~~renew~~purchase the ~~leases~~leased assets at aexpiration ~~fixed~~of ~~price or to purchase~~ the ~~property~~lease ~~for~~at fair market value of $7.7 million. See Note ~~7 regarding the status of these alternatives~~16.

Additionally, in 1996, PNM entered into a PPA for the rights to all the output of the Delta generating plant through June 2020. The PPA is accounted for as an operating lease. The gas turbine generating unit is operated by Delta, which is a variable interest entity. See Note 9. The plant is mainly used to meet peak load requirements.

For reasons similar to the PVNGS sale and leaseback transactions, PNM built the EIP Transmission Line and sold it in sale and leaseback transactions in 1985. The EIP line is a 216 mile, 345 kilovolt line with a capacity of 200 MW. PNM currently owns 60% and operates the other 40% of the EIP line under the terms of a lease agreement. The lease expires in 2015 with fixed-rate and fair market value renewal options and a fair market value purchase option.

The future lease payments shown below for the PVNGS and EIP leases have been reduced by amounts that will be returned to PNM through its ownership in related lessor notes.

	PVNGSUnits 1&2		EIP		Delta		Total
	(In thousands)
2012	$	25,078	$	498	$	5,956	$	31,532
2013	$	27,427	$	—	$	5,956	$	33,383
2013	27,427		2,845		5,956		36,228
2014	32,236		4,267		5,956		42,459
2014	32,236		2,845		5,956		41,037
2015	17,082		—		5,956		23,038
2015	17,082		1,422		5,956		24,460
2016	3,270		—		5,956		9,226
Thereafter	—		—		21,342		21,342
2017	—		—		5,956		5,956
Total	$	105,093	$	7,610	$	51,122	$	163,825
Thereafter	—		—		15,385		15,385
Total	$	80,015	$	4,267	$	45,165	$	129,447

The above table includes payments under the PVNGS leases through their existing expiration. As discussed in Note 7, PNM gave notice to the lessors under the PVNGS Unit 1 leases in 2013 that PNM would renew the leases. The renewal payments under the PVNGS Unit 1 leases are $16.5 million, which are not included above. The renewal period is yet to be determined, but will be between two and eight years. See Sources of Power in Part I, Item 1, Investments in Note 1, and Note 7 for additional information.

~~Commitments~~A- ~~and Contractual Obligations~~42

The following table sets forth PNMR’s long-term contractual obligations as of December 31, 2011. See Note 7 for further details about the Company’s significant leases:

	Payments Due
Contractual Obligations	2012		2013-2014		2015-2016		2017 and Thereafter		Total
	(In thousands)
Long-term debt (a)	$	2,387	$	52,530	$	181,892	$	1,442,070	$	1,678,879
Interest on long-term debt (b)	117,042		232,743		212,583		728,097		1,290,465
Operating leases (c)	49,923		111,058		58,288		103,669		322,938
Transmission reservation payments	13,421		16,665		3,316		16,980		50,382
Coal contracts (d)	58,319		119,369		116,267		46,411		340,366
Coal mine decommissioning	3,207		1,311		3,164		67,999		75,681
Nuclear decommissioning funding requirements (e)	2,600		5,200		5,200		48,138		61,138
Outsourcing	6,385		4,541		1,300		—		12,226
Pension and retiree medical (f)	86,376		75,151		25,451		—		186,978
Construction expenditures (g)	286,654		541,612		478,673		—		1,306,939
Total (h)	$	626,314	$	1,160,180	$	1,086,134	$	2,453,364	$	5,325,992

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Table of Contents

~~(a)~~Commitments ~~Represents~~and ~~total~~Contractual ~~long-term debt excluding unamortized discount of $4.9 million.~~Obligations

The following table sets forth PNMR’s long-term contractual obligations as of December 31, 2012. See Note 7 for further details about the Company’s significant leases:



	Payments Due
Contractual Obligations	2013		2014-2015		2016-2017		2018 and Thereafter		Total
	(In thousands)
Long-term debt (a)	$	2,530	$	231,892	$	57,000	$	1,385,070	$	1,676,492
Interest on long-term debt (b)	116,377		227,180		198,033		606,679		1,148,269
Operating leases (c)	44,040		83,525		28,309		94,883		250,757
Transmission reservation payments	13,443		14,859		11,276		19,667		59,245
Coal contracts (d)	61,809		125,687		101,853		—		289,349
Coal mine decommissioning (e)	3,907		1,327		2,928		72,983		81,145
Nuclear decommissioning funding requirements (f)	2,600		5,200		5,200		60,812		73,812
Outsourcing	5,573		7,771		3,629		—		16,973
Pension and retiree medical (g)	64,542		35,719		8,274		—		108,535
Construction expenditures (h)	372,807		827,969		581,114		—		1,781,890
Total (i)	$	687,628	$	1,561,129	$	997,616	$	2,240,094	$	5,486,467


(a)	Represents total long-term debt excluding unamortized discounts of $4.2 million.


(b)	Represents interest payments during the period.

(c) The operating lease amounts include amounts due to Delta. The amounts include payments under the PVNGS leases through their existing expiration. As discussed in Note 7, PNM gave notice to the lessors under the PVNGS Unit 1 leases in 2013 that PNM would renew the leases. The renewal payments under the PVNGS Unit 1 leases are $16.5 million, which are not included in the above table. The renewal period is yet to be determined, but will be between two and eight years. The amounts in the above table are net of amounts to be returned to PNM as payments on its investments in related PVNGS lessor notes. See Investments in Note 1 and Note 7. See Note 9 for additional information about the Delta operating lease, including the potential purchase of Delta.


(d)	Represents only certain minimum payments that may be required under the coal contracts if no deliveries are made.

(e) ~~These~~Includes ~~obligations~~funding ~~represent~~of ~~funding~~the ~~based~~trust onestablished for post-term reclamation related to the ~~current~~mines ~~rate~~serving ofSJGS. ~~return~~See onNote ~~investments~~16.

(f) ~~The~~These ~~Company~~obligations ~~only~~represent ~~forecasts~~ funding ~~for~~based ~~its~~on ~~pension~~the ~~and~~current ~~retiree~~rate ~~medical~~of ~~plans~~return ~~for~~on ~~the next five years~~investments.

(g) ~~Represents~~The ~~forecasted~~Company ~~capital~~only ~~expenditures,~~forecasts ~~including~~funding ~~nuclear~~for ~~fuel,~~its ~~under~~pension ~~which~~and ~~substantial~~retiree ~~commitments~~medical ~~have~~plans ~~been made. The Company only forecasts capital expenditures~~ for the next five years.

(h) ~~PNMR~~Represents isforecasted ~~unable~~construction toexpenditures, ~~reasonably~~including ~~estimate~~nuclear ~~the~~fuel, ~~timing~~under ofwhich ~~liability~~substantial ~~and~~commitments ~~interest~~have ~~payments~~been ~~for~~made. ~~uncertain~~See ~~income~~Note ~~tax~~14. ~~positions~~The inCompany ~~individual~~only ~~years~~forecasts ~~due~~capital toexpenditures ~~uncertainties~~for in the ~~timing~~next offive ~~the~~years. ~~effective~~The ~~settlement~~construction ofexpenditures ~~tax~~include ~~positions.~~the ~~Therefore,~~purchase ~~PNMR’s liability~~ of ~~$19.6~~the ~~million~~leased ~~and~~portion ~~interest payable~~ of ~~$1.1~~the ~~million~~EIP ~~are~~at ~~not~~the ~~reflected~~expiration inof ~~this~~the ~~table~~lease. ~~Amounts~~See ~~PNM~~Capital isRequirements ~~obligated to pay Valencia are not included~~ above ~~since~~and ~~Valencia is consolidated by PNM in accordance with GAAP. See~~ Note 916. ~~No amounts are included above for the New Mexico Wind Energy PPA since there are no minimum payments required under that agreement.~~

(i)

PNMR is unable to reasonably estimate the timing of liability and interest payments for uncertain income tax positions in individual years due to uncertainties in the timing of the effective settlement of tax positions. Therefore, PNMR’s liability of $19.2 million and interest payable of $1.1 million are not reflected in this table. Amounts PNM is obligated to pay Valencia are not included above since Valencia is consolidated by PNM in accordance with GAAP. See Note 9. No amounts are included above for the New Mexico Wind Energy PPA since there are no minimum payments required under that agreement.

Contingent Provisions of Certain Obligations

PNMR, PNM, and TNMP have a number of debt obligations and other contractual commitments that contain contingent provisions. Some of these, if triggered, could affect the liquidity of the Company. In the unlikely event that the contingent requirements were to be triggered, PNMR, PNM, or TNMP could be required to provide security, immediately pay outstanding obligations, or be prevented from drawing on unused capacity under certain credit agreements. The most significant consequences resulting from these contingent requirements are detailed in the discussion below.

The PNMR Revolving Credit Facility, ~~the~~ PNM Revolving Credit Facility, and ~~the~~ TNMP Revolving Credit Facility, contain “ratings triggers,” for pricing purposes only. If PNMR, PNM, or TNMP is downgraded or upgraded by the ratings agencies, the result would be an increase or decrease in interest cost. In addition, these credit facilities contain contingent requirements that require the maintenance of debt-to-capital ratios of less than 65%. In the calculation of debt for PNMR and PNM, the present value of payments under the PVNGS and EIP leases are considered debt. If that ratio were to exceed 65%, the entity could be required to repay all borrowings under its facility, be prevented from borrowing on the unused capacity under the facility, and be required to provide collateral for all outstanding letters of credit issued under the facility.

If a contingent requirement were to be triggered under the PNM Revolving Credit Facility resulting in an acceleration of the repayment of outstanding loans under the PNM Revolving Credit Facility, a crossA-~~default~~ provision in the PVNGS leases could occur if the accelerated amount is not paid. If a cross-default provision is triggered, the PVNGS lessors have the ability to accelerate their rights under the leases, including acceleration of all future lease payments.43

Table of Contents

result would be an increase or decrease in interest cost. In addition, the revolving credit facilities, as well as the PNMR Term Loan Agreement and TNMP 2011 Term Loan, each contain a covenant requiring the maintenance of debt-to-capital ratios of less than 65%. In the calculation of debt for PNMR and PNM, the present value of payments under the PVNGS and EIP leases are considered debt. If that ratio were to exceed 65%, the entity could be required to repay all borrowings under its facility, be prevented from borrowing on the unused capacity under the facility, and be required to provide collateral for all outstanding letters of credit issued under the facility.

If a contingent requirement were to be triggered under the PNM Revolving Credit Facility resulting in an acceleration of the repayment of outstanding loans under the PNM Revolving Credit Facility, a cross-default provision in the PVNGS leases could occur if the accelerated amount is not paid. If a cross-default provision is triggered, the PVNGS lessors have the ability to accelerate their rights under the leases, including acceleration of all future lease payments. The PNMR Term Loan Agreement also includes a cross-default provision.

PNM's standard purchase agreement for the procurement of gas for its fuel needs contains a contingent requirement that could require PNM to provide collateral for its gas purchase obligations if the seller were to reasonably believe that PNM was unable to fulfill its payment obligations under the agreement.

The master agreement for the sale of electricity in the WSPP contains a contingent requirement that ~~requires~~could require PNM to provide collateral if the credit ratings on its debt falls below investment grade. ~~Additionally,~~The ~~PNM~~WSPP ~~utilizes~~agreement ~~standard~~also ~~derivative~~contains ~~contracts~~a tocontingent ~~financially~~requirement, ~~hedge~~commonly ~~and~~called ~~trade~~a ~~energy. These~~material ~~agreements~~adverse ~~contain~~change ~~contingent~~provision, ~~requirements~~which ~~that~~could require PNM to provide ~~security~~collateral if ~~the~~a ~~credit~~material ~~rating~~adverse onchange in its ~~debt~~financial ~~falls~~condition ~~below~~or ~~investment~~operations ~~grade~~were to occur. ~~The~~Additionally, ~~WSPP~~PNM ~~agreement~~utilizes ~~also~~standard ~~contains~~derivative acontracts ~~contingent~~to ~~requirement,~~financially ~~commonly~~hedge ~~called~~and atrade ~~material~~energy. These ~~adverse~~agreements ~~change~~contain ~~provision,~~contingent ~~which~~requirements ~~could~~that require PNM to provide ~~collateral~~security if athe ~~material~~credit ~~adverse~~rating ~~change~~on in its ~~financial~~debt ~~condition~~falls orbelow ~~operations~~investment ~~were to occur~~grade.

No conditions have occurred that would result in any of the above contingent provisions being implemented.

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Capital Structure

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

	December 31,
PNMR	~~2011~~2012		~~2010~~2011
PNMR common equity	48.39	%	4748.83	%
Convertible preferred stock	—		3.1	%
Preferred stock of subsidiary	0.3	%	0.3	%
Preferred stock of subsidiary	0.3	%	0.4	%
Long-term debt	50.8	%	51.4	%
Long-term debt	51.4	%	48.7	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	4950.75	%	5149.37	%
Preferred stock	0.5	%	0.5	%
Long-term debt	49.80	%	4849.28	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	59.8	%	59.48	%
Long-term debt	40.2	%	40.62	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In ~~2011~~2012, PNM's generating plants emitted approximately 76.17 million metric tons of CO2, which comprises the vast majority of its GHG. By comparison, the total GHG in the United States in ~~2009~~2010, the latest year for which EPA has published this data, were approximately 6.68 billion metric tons, of which approximately 5.57 billion metric tons were CO2. According to EPA data, electricity generation accounted for approximately 2.23 billion metric tons, or 40%, of the CO2 emissions.

PNM has several programs underway to reduce GHG from its generating plants, thereby reducing its exposure to climate change regulation. See Note 17. In 2011, PNM completed construction of 22 MW of utilityA-~~scale~~ solar generation located at five sites on PNM's system throughout New Mexico. Additionally, PNM has a customer distributed solar generation program that is expected to grow distributed solar from the 14 MW installed at the end of 2011 to over 35 MW in the next year. Once fully subscribed, the distributed solar programs will reduce PNM's demand for fossil-fueled electricity generation by 82 GWh per year. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with an annual budget of over $17 million, that projects electricity savings in 2012 of an estimated 60 GWh. Over the next 19 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 12,870 GWh of electricity, which will avoid at least 6.1 million metric tons of CO2 based upon projected emissions from PNM's system-wide portfolio with and without these programs. These estimates are subject to change given that it is difficult to accurately estimate avoidance because of the high uncertainty of many of the underlying variables and complex interrelationships between those variables, including changes in demand for electricity. 44

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

Approximately 81.9% of PNM's owned and leased generating capacity at December 31, 2011 consisted of coal or gas-fired generation that produces GHG, all of which is located within the United States. The Company does not anticipate any direct impact from any near-term international accords. Based on current forecasts, the Company does not expect its output of GHG from existing sources to increase significantly in the near-term. Many factors affect the amount of GHG, including plant

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~~performance~~PNM has several programs underway to reduce GHG from its generating plants, thereby reducing its exposure to climate change regulation. ~~For~~ See ~~example~~Note 17. In 2011, ifPNM ~~PVNGS~~completed ~~experienced~~construction ~~prolonged~~of ~~outages~~22 MW of utility-scale solar generation located at five sites on PNM's system throughout New Mexico. In 2013, PNM ~~might~~will be ~~required~~expanding toits ~~utilize~~renewable ~~other~~energy ~~power~~portfolio ~~supply~~by ~~resources~~constructing ~~such~~21.5 asMW ~~gas~~of utility-~~fired~~scale solar generation, ~~which~~that ~~could~~will ~~increase~~be ~~GHG~~on-line by the end of the year and has signed a 20 year PPA for the output of a 10 MW geothermal facility to be in service by January 1, 2014. IfAdditionally, ~~new~~PNM ~~natural~~has ~~gas-fired~~a customer distributed solar generation ~~resources~~program ~~are~~that ~~added~~is expected to ~~meet~~grow ~~increased~~distributed ~~load~~solar ~~anticipated~~from inalmost ~~PNM's~~20 ~~current~~MW ~~IRP,~~installed ~~GHG~~at ~~would~~the beend ~~incrementally~~of ~~increased~~2012 to over 44 MW by the end of 2014. ~~Because~~Once offully subscribed, the ~~Company~~distributed solar programs will reduce PNM's ~~dependence~~production onfrom fossil-fueled electricity generation, ~~any~~by ~~legislation~~116 ~~that~~GWh ~~imposes~~per year. PNM offers its customers a ~~limit~~comprehensive orportfolio ~~cost~~of onenergy ~~GHG~~efficiency ~~will~~and ~~impact~~load ~~the~~management ~~cost~~programs, atwith ~~which~~a 2012 budget of over $17 million, that PNM estimates saved approximately 71 GWh of electricity isin ~~produced~~2012. ~~While~~Over the next 18 years, PNM ~~expects~~projects tothe beexpanded ~~entitled~~energy toefficiency ~~recover~~and ~~that~~load ~~cost~~management ~~through~~programs ~~rates,~~will provide the ~~timing~~equivalent ~~and~~of ~~outcome~~approximately 12,185 GWh of ~~proceedings~~electricity, ~~for~~which ~~cost~~will ~~recovery~~avoid isat ~~uncertain~~least 6. In1 ~~addition,~~million tometric ~~the~~tons ~~extent~~of ~~that~~CO2 ~~any~~based ~~additional~~upon ~~costs~~projected ~~are~~emissions ~~recovered~~from ~~through~~PNM's ~~rates,~~system-wide ~~customers~~portfolio ~~may~~with ~~reduce~~and ~~their~~without ~~demand,~~these ~~relocate~~programs. These ~~facilities~~estimates are subject to ~~other~~change ~~areas~~given ~~with~~that ~~lower~~it ~~energy~~is ~~costs,~~difficult orto ~~take~~accurately ~~other~~estimate ~~actions~~avoidance ~~that~~because ~~ultimately~~of ~~will~~the ~~adversely~~high ~~impact~~uncertainty of many of the ~~Company~~underlying variables and complex interrelationships between those variables, including changes in demand for electricity.

~~Given~~Management ~~the~~periodically ~~geographic~~updates ~~location~~the ofBoard ~~its~~on ~~facilities~~implementation ~~and~~of ~~customers,~~corporate ~~PNM~~environmental ~~generally~~policy ~~has~~and ~~not been exposed to~~ the ~~extreme~~Company's ~~weather~~environmental ~~events~~management ~~and~~systems, ~~other~~promotion ~~physical~~of ~~impacts~~energy ~~commonly attributed to climate change~~efficiency, ~~with~~and ~~the~~use ~~possible exception~~ of ~~periodic~~renewable ~~drought conditions~~resources. ~~Climate~~ The ~~changes~~Board ~~are~~is ~~generally~~also ~~not~~advised ~~expected~~of ~~to have material consequences in~~ the ~~near-term. Drought~~Company's ~~conditions~~practices inand ~~northwestern~~procedures ~~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~~assess ~~precipitation in~~ the ~~San~~sustainability ~~Juan~~impacts ~~basin. PNM~~of ~~also~~operations ~~has~~on ~~a supplemental water contract in place with~~ the ~~Jicarilla Tribe to help address any water shortages from primary sources~~environment. The ~~contract~~Board ~~expires~~regularly ~~December~~considers ~~31,~~associated ~~2016. TNMP~~issues ~~has~~around ~~operations~~climate inchange, the ~~Gulf~~Company's ~~coast~~GHG ~~area of Texas~~exposures, ~~which experiences periodic hurricanes~~ and ~~drought~~potential ~~conditions. In~~financial ~~addition~~consequences tothat ~~potentially~~might ~~causing~~result ~~physical~~from ~~damage~~potential tofederal ~~TNMP owned facilities, which disrupt the ability to generate, transmit,~~ and/or ~~distribute~~state ~~energy,~~regulation ~~hurricanes~~of ~~can temporarily reduce customers' usage and demand for energy~~GHG.

Approximately 81.8% of PNM's owned and leased generating capacity at December 31, 2012 consisted of coal or gas-fired generation that produces GHG, all of which is located within the United States. The Company does not anticipate any direct impact from any near-term international accords. Based on current forecasts, the Company does not expect its output of GHG from existing sources 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. If new natural gas-fired generation resources are added to meet increased load as anticipated in PNM's current IRP, GHG would be incrementally increased. As described in Note 16, on February 15, 2013, PNM, NMED, and EPA agreed to pursue a strategy to address the regional haze requirements of the CAA at the coal-fired SJGS, which would include the shutdown of SJGS Units 2 and 3. If implemented, shutdown of those units would reduce PNM's GHG. That agreement also contemplates that gas-fired generation would be built to partially replace the retired capacity. Although replacement power strategies have not been finalized, the reduction in GHG from the retirement of coal-fired generation would be greater than the increase in GHG from replacement with gas-fired generation.

Because of PNM'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 PNM.

Given the geographic location of its facilities and customers, PNM generally has not been exposed to the extreme weather events and other physical impacts commonly attributed to climate change, with the 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 River 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 on December 31, 2016. TNMP has operations in the Gulf Coast area of Texas, which experiences periodic hurricanes and drought conditions. In addition to potentially causing physical damage to TNMP owned facilities, which disrupt the ability to transmit and/or distribute energy, hurricanes can temporarily reduce customers' usage and demand for energy.

EPA Regulation

In April 2007, the ~~U.S.~~United States Supreme Court held that EPA has the authority to regulate GHG under the CAA. This decision heightened the importance of this issue for the energy industry. In December 2009, EPA released its ~~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. In May 2010, EPA released the final PSD and Title V Greenhouse Gas Tailoring Rule (the "Tailoring Rule") to address GHG from stationary sources under the CAA permitting programs. The purpose of the rule is to “tailor” the applicability of two programs, PSD and

In May 2010, EPA released the final PSD and Title V Greenhouse Gas Tailoring Rule to address GHG from stationary sources under the CAA permitting programs. The purpose of the rule is to “tailor” the applicability of two programs, PSD and Title V operating permit programs, to avoid impacting millions of small GHG emitters. The rule focuses on the largest sources of GHG, including fossilA-~~fueled~~ electric generating units. This program currently covers new construction projects that emit GHG of at least 100,000 tons per year (even if PSD is not triggered for other pollutants). In addition, modifications at existing facilities that increase GHG by at least 75,000 tons per year will be subject to PSD permitting requirements, even if they do not significantly increase emissions of any other pollutant. An additional phase is scheduled to become effective in July 2013 and may regulate even smaller GHG sources. All of PNM's fossil-fueled generating plants are potentially subject to the Tailoring Rule because of the magnitude of non-GHG, but the plants do not have any currently planned projects that would trigger PSD permitting for GHGs. 45

OnTable ~~December~~of ~~23,~~Contents 2010, EPA announced a proposed rulemaking timeline for CAA NSPS for GHG from power plants and petroleum refineries. EPA is expected to announce the proposed GHG NSPS in the near future. The EPA previously missed several deadlines to propose the rules, the most recent being in January 2012. The deadline for EPA to publish the final standards is still May 26, 2012, although final action is not expected until late 2012. The CAA's NSPS provisions include separate programs for new and modified facilities and for existing facilities. EPA will establish NSPS for new and modified facilities directly, while EPA will establish emission guidelines for existing facilities through a cooperative federal-state process.

~~EPA~~Title ~~regulation~~V ofoperating ~~GHG~~permit ~~from~~programs, ~~large~~to ~~stationary~~avoid ~~sources~~impacting ~~will~~millions ~~impact~~of ~~PNM's~~small ~~operations~~GHG ~~due~~emitters. The torule focuses on the ~~Company's~~largest ~~reliance~~sources onof GHG, including fossil-fueled electric ~~generation~~generating units. ~~The~~This ~~impact~~program tocurrently ~~PNM~~covers new construction projects that emit GHG of at least 100,000 tons per year (even if PSD is ~~unknown~~not ~~because~~triggered ~~the~~for ~~regulatory~~other ~~requirements~~pollutants). In addition, ~~including~~modifications ~~Best~~at ~~Available~~existing ~~Control~~facilities ~~Technology~~that ~~implications~~increase ~~and~~GHG ~~NSPS~~by at least 75,000 tons per year will be subject to PSD permitting requirements, ~~are~~even ~~still~~if ~~developing~~they do not significantly increase emissions of any other pollutant. ~~Impacts~~EPA ~~could~~had ~~involve~~indicated ~~investments~~ in ~~efficiency~~its ~~improvements~~original ~~and/or~~Tailoring ~~control~~Rule ~~technologies~~that atit might extend PSD regulation to smaller emission sources. However, on July 3, 2012, EPA finalized the third phase of the rule by keeping the permitting thresholds where they are. All of PNM's fossil-fueled generating plants~~. It~~ isare ~~also~~potentially ~~possible~~subject ~~that~~to the ~~costs~~Tailoring ofRule ~~such~~because ~~improvements~~of orthe ~~technologies~~magnitude ~~could~~of ~~impact~~non-GHG, but the ~~economic~~existing ~~viability~~plants ofdo ~~some~~not ~~plants~~have any currently planned projects that would trigger PSD permitting for GHG. Any newly constructed power plant would likely be subject to the Tailoring Rule.

On June 26, 2012, the D.C. Circuit rejected challenges to EPA's 2009 GHG endangerment finding, GHG emission standards for light-duty vehicles, PSD Interpretive Memorandum (EPA's so-called GHG "Timing Rule"), and Tailoring Rule. The Court found that EPA's endangerment finding and its light-duty vehicle rule "are neither arbitrary nor capricious," that "EPA's interpretation of the governing CAA provisions is unambiguously correct," and that "no petitioner has standing to challenge the Timing and Tailoring Rules."

On March 27, 2012, EPA issued its proposed carbon pollution standards for the emission of GHG from new fossil-fueled electric generating units (“EGUs”). The proposed NSPS sets a limit of 1,000 lb CO₂/MWh and covers newly constructed fossil-fueled EGUs that are larger than 25 MW. The proposed limit is based on the performance of natural gas combined cycle technology. Therefore, coal-fired power plants would likely only be able to comply with the standard by using carbon capture and sequestration technology. The proposed rule includes an exemption for simple cycle EGUs. However, during the comment period, EPA solicited comments on whether to drop the exemption and instead exempt any fossil-fueled EGU that limits electric generation to one-third of its annual generating capacity. The proposed rule, as written, does not include limits that apply to existing power plants, or proposed plants that already have a complete preconstruction permit and commence construction within 12 months of the issuance of the proposed rule. The proposal is the first NSPS issued for CO₂, and although it is limited to new sources, it has potential far-reaching implications for the utility industry. When finalized, the standard could serve as the floor for BACT analysis for PSD permitting for new GHG sources under the Tailoring Rule. The proposed rule was published in the Federal Register on April 13, 2012. EPA accepted comment on the proposed rule through June 25, 2012.

Completion of the proposed NSPS for new EGUs is a prerequisite for EPA to promulgate GHG standards for existing sources. An EPA proposal to establish a GHG NSPS for existing sources is expected sometime in 2013. In setting the standards, EPA has historically used technology-based performance standards on emission rates, but currently there are no GHG control technologies in existence that can provide a basis for an existing source NSPS.

EPA regulation of GHG from large stationary sources will impact PNM's operations due to its reliance on fossil-fueled electric generation. The impact to PNM is unknown because the regulatory requirements, including BACT implications and NSPS requirements, are still developing. Impacts could involve investments in efficiency improvements and/or control technologies at the fossil-fueled generating plants. Currently, there are no commercially viable GHG control technologies although such technologies may become viable in the future. It is also possible that the costs of such improvements or technologies could impact the economic viability of some plants.

Federal Legislation

Prospects for enactment of legislation imposing a new or enhanced regulatory program to address climate change in the ~~current~~new Congress are ~~extremely~~ unlikely in 2013, although ~~Congress~~there ~~could~~is ~~address~~growing ~~these~~interest ~~issues~~among atsome apolicymakers ~~future~~in ~~time~~addressing climate change and there may be legislation in the future. Instead, EPA is ~~likely~~ the primary venue for GHG regulation in the near future, especially for coal-fired units. PNM has assessed, and continues to assess, the impacts of potential climate change legislation or regulation on its business. This assessment is preliminary, and future changes arising out of the legislative or regulatory process could impact the assessment significantly. PNM's assessment includes assumptions regarding the specific GHG limits, the timing of implementation of these limits, the 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 PNM, and could jeopardize the economic viability of certain generating facilities. See Note 16. 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. PNM's assessment process is ongoing, but too preliminary and speculative at this time for the meaningful prediction of financial impact.

~~The~~A- 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 46

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of technologies for renewable energy and to reduce emissions, the cost of emissions allowances, the degree to which offsets may be used for compliance, and provisions for cost containment. Moreover, the assessment assumes various market reactions such as with respect to the price of coal and gas and regional plant economics. These assumptions, at best, are preliminary and speculative. However, based upon these assumptions, the enactment of climate change legislation would likely, among other things, result in significant compliance costs, including significant capital expenditures by the Company, and could jeopardize the economic viability of certain generating facilities. See Note 16. In turn, these consequences would lead to increased costs to customers and could affect results of operations, cash flows, and financial condition if the incurred costs are not fully recovered through regulated rates. Higher rates could also contribute to reduced demand for electricity. The Company's assessment process is ongoing, but too preliminary and speculative at this time for the meaningful prediction of financial impact.

State and Regional Activity

Pursuant to New Mexico law, each utility must submit an IRP to the NMPRC every three years to evaluate renewable energy, energy efficiency, load management, distributed generation, and conventional supply-side resources on a consistent and comparable basis. The IRP is required to take into consideration risk and uncertainty of fuel supply, price volatility, and costs of anticipated environmental regulations when evaluating resource options to meet supply needs of the utility's customers. The NMPRC issued an order in June 2007, requiring that New Mexico utilities factor a standardized cost of carbon emissions into their IRPs using prices ranging between $8 and $40 per metric ton of CO2 emitted and escalating these costs by 2.5% per year. Under the NMPRC order, each utility must analyze these standardized prices as projected operating costs. Reflecting the developing nature of this issue, the NMPRC order states that these prices may be changed in the future to account for additional information or changed circumstances. However, PNM is required to use these prices for purposes of its IRP, and the prices may not reflect the costs that it ultimately will incur. PNM's IRP filed with the NMPRC on July 18, 2011 (Note 17), showed that while consideration of the NMPRC required carbon emissions costs did not significantly change the resource decisions regarding future facilities over the next 20 years, it did slightly impact the projected in-service dates of some of the identified resources. Much higher GHG costs than assumed in the NMPRC analysis are necessary to impact future resource decisions. The primary consequence of the standardized cost of carbon emissions was an increase to generation portfolio costs. In recent years, New Mexico also adopted regulations to directly limit GHG from larger sources, including electric generation units. However, these regulations were recently repealed. In November 2010, the EIB adopted a regional GHG cap and trade program proposed by the NMED. The NMED GHG program was intended to implement, in New Mexico, the regional cap and trade program developed by the Western Climate Initiative (“WCI) which is an organization formerly comprised of seven western states, including New Mexico, and three Canadian provinces. The NMED GHG regulation would have capped GHG emissions based on a 2011 emission baseline. Thereafter, NMED would grant GHG allowances to covered sources based

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