10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

Commission File	Name of Registrants, State of Incorporation,	I.R.S. Employer
Number	Address and Telephone Number	Identification No.
001-32462	PNM Resources, Inc.	85-0468296
	(A New Mexico Corporation)
	414 Silver Ave. SW
	Albuquerque, New Mexico 87102-3289
	(505) 241-2700
001-06986	Public Service Company of New Mexico	85-0019030
	(A New Mexico Corporation)
	414 Silver Ave. SW
	Albuquerque, New Mexico 87102-3289
	(505) 241-2700
002-97230	Texas-New Mexico Power Company	75-0204070
	(A Texas Corporation)
	577 N. Garden Ridge Blvd.
	Lewisville, Texas 75067
	(972) 420-4189

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

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

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

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

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

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

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

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

As of October 24, 2014, 79,653,624 shares of common stock, no par value per share, of PNMR were outstanding.

The total number of shares of common stock of PNM outstanding as of October 24, 2014 was 39,117,799 all held by PNMR (and none held by non-affiliates).

The total number of shares of common stock of TNMP outstanding as of October 24, 2014 was 6,358 all held indirectly by PNMR (and none held by non-affiliates).

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

This combined Form 10-Q is separately filed by PNMR, PNM, and TNMP.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.  Each registrant makes no representation as to information relating to the other registrants.  When this Form 10-Q is incorporated by reference into any filing with the SEC made by PNMR, PNM, or TNMP, as a registrant, the portions of this Form 10-Q that relate to each other registrant are not incorporated by reference therein.

2

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

INDEX

	Page No.
GLOSSARY	4
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
PNM RESOURCES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	7
Condensed Consolidated Statements of Comprehensive Income	8
Condensed Consolidated Statements of Cash Flows	9
Condensed Consolidated Balance Sheets	11
Condensed Consolidated Statement of Changes in Equity	13
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	14
Condensed Consolidated Statements of Comprehensive Income	15
Condensed Consolidated Statements of Cash Flows	16
Condensed Consolidated Balance Sheets	18
Condensed Consolidated Statement of Changes in Equity	20
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	21
Condensed Consolidated Statements of Comprehensive Income	22
Condensed Consolidated Statements of Cash Flows	23
Condensed Consolidated Balance Sheets	24
Condensed Consolidated Statement of Changes in Common Stockholder's Equity	26
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	72
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	99
ITEM 4. CONTROLS AND PROCEDURES	102
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	102
ITEM 1A. RISK FACTORS	103
ITEM 6. EXHIBITS	103
SIGNATURE	105

3

GLOSSARY

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

4

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
New Mexico Wind	New Mexico Wind Energy Center
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NMAG	New Mexico Attorney General
NMED	New Mexico Environment Department
NMIEC	New Mexico Industrial Energy Consumers Inc.
NMPRC	New Mexico Public Regulation Commission
NOx	Nitrogen Oxides
NOPR	Notice of Proposed Rulemaking
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
NSR	New Source Review
OCI	Other Comprehensive Income
OPEB	Other Post Employment Benefits
OSM	United States Office of Surface Mining Reclamation and Enforcement
PNM	Public Service Company of New Mexico and Subsidiaries
PNM 2014 Term Loan Agreement	PNM’s $175.0 Million Unsecured Term Loan Facility
PNM New Mexico Credit Facility	PNM’s $50.0 Million Unsecured Revolving Credit Facility
PNM Revolving Credit Facility	PNM’s $400.0 Million Unsecured Revolving Credit Facility
PNM Term Loan Agreement	PNM’s $75.0 Million Unsecured Term Loan Facility
PNMR	PNM Resources, Inc. and Subsidiaries
PNMR Development	PNMR Development and Management Corporation
PNMR Revolving Credit Facility	PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan Agreement	PNMR’s $100.0 Million Unsecured Term Loan Facility
PPA	Power Purchase Agreement
PSD	Prevention of Significant Deterioration
PUCT	Public Utility Commission of Texas
PV	Photovoltaic
PVNGS	Palo Verde Nuclear Generating Station
RCRA	Resource Conservation and Recovery Act
RCT	Reasonable Cost Threshold
REA	New Mexico’s Renewable Energy Act of 2004
REC	Renewable Energy Certificates
Red Mesa Wind	Red Mesa Wind Energy Center
REP	Retail Electricity Provider
Rio Bravo	Rio Bravo Generating Station, formerly known as Delta

5

RMC	Risk Management Committee
RPS	Renewable Energy Portfolio Standard
RSIP	Revised State Implementation Plan
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
SJPPA	San Juan Project Participation Agreement
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
SPS	Southwestern Public Service Company
S&P	Standard and Poor’s Ratings Services
TECA	Texas Electric Choice Act
Tenth Circuit	United States Court of Appeals for the Tenth Circuit
TNMP	Texas-New Mexico Power Company and Subsidiaries
TNMP 2011 Term Loan Agreement	TNMP’s $50.0 Million Secured Term Loan
TNMP Revolving Credit Facility	TNMP’s $75.0 Million Revolving Credit Facility
TNP	TNP Enterprises, Inc. and Subsidiaries
Tucson	Tucson Electric Power Company
Valencia	Valencia Energy Facility
VaR	Value at Risk
WACC	Weighted Average Cost of Capital
WEG	WildEarth Guardians

6

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands, except per share amounts)
Electric Operating Revenues	$	413,951		$	399,730		$	1,089,008		$	1,064,993
Operating Expenses:
Cost of energy	132,499			114,674			354,532			325,039
Administrative and general	42,190			46,915			131,283			134,744
Energy production costs	43,287			41,142			136,422			131,546
Regulatory disallowances	—			1,735			—			1,735
Depreciation and amortization	44,295			42,743			128,424			125,189
Transmission and distribution costs	16,884			17,248			49,857			50,690
Taxes other than income taxes	17,997			17,534			51,641			49,739
Total operating expenses	297,152			281,991			852,159			818,682
Operating income	116,799			117,739			236,849			246,311
Other Income and Deductions:
Interest income	2,084			2,264			6,241			7,731
Gains on available-for-sale securities	962			2,188			8,234			6,935
Other income	2,895			3,254			7,648			7,577
Other (deductions)	(2,084		)	(5,970		)	(7,185		)	(13,516		)
Net other income and deductions	3,857			1,736			14,938			8,727
Interest Charges	30,115			30,365			89,621			92,279
Earnings before Income Taxes	90,541			89,110			162,166			162,759
Income Taxes	31,055			30,296			53,368			58,600
Net Earnings	59,486			58,814			108,798			104,159
(Earnings) Attributable to Valencia Non-controlling Interest	(3,701		)	(4,127		)	(11,140		)	(10,904		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Net Earnings Attributable to PNMR	$	55,653		$	54,555		$	97,262		$	92,859
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.70		$	0.68		$	1.22		$	1.16
Diluted	$	0.69		$	0.68		$	1.21		$	1.15
Dividends Declared per Common Share	$	0.185		$	0.165		$	0.555		$	0.495

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

7

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Net Earnings	$	59,486		$	58,814		$	108,798		$	104,159
Other Comprehensive Income:
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(137), $(4,143), $(3,946) and $(7,544)	210			6,322			6,256			11,512
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,059, $925, $4,547 and $3,639	(1,628		)	(1,411		)	(6,997		)	(5,551		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(508), $(631), $(1,524) and $(1,893)	780			960			2,340			2,880
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $128, $53 and $127	—			(238		)	(100		)	(236		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $3, $(19), $(58) and $(54)	(6		)	35			109			99
Total Other Comprehensive Income (Loss)	(644		)	5,668			1,608			8,704
Comprehensive Income	58,842			64,482			110,406			112,863
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,701		)	(4,127		)	(11,140		)	(10,904		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Comprehensive Income Attributable to PNMR	$	55,009		$	60,223		$	98,870		$	101,563

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

8

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	108,798		$	104,159
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	157,687			157,856
Deferred income tax expense	55,553			57,878
Net unrealized (gains) on commodity derivatives	(67		)	(5,858		)
Realized (gains) on available-for-sale securities	(8,234		)	(6,935		)
Stock based compensation expense	4,680			4,315
Regulatory disallowances	—			1,735
Other, net	(642		)	1,384
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(22,158		)	(23,731		)
Materials, supplies, and fuel stock	5,494			(724		)
Other current assets	(19,816		)	(6,667		)
Other assets	30,502			21,656
Accounts payable	79			(17,786		)
Accrued interest and taxes	32,488			126,218
Other current liabilities	(21,197		)	(32,111		)
Other liabilities	3,074			(70,379		)
Net cash flows from operating activities	326,241			311,010
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(293,361		)	(233,928		)
Proceeds from sales of available-for-sale securities	82,222			179,336
Purchases of available-for-sale securities	(81,644		)	(181,423		)
Return of principal on PVNGS lessor notes	20,758			23,357
Purchase of Rio Bravo	(36,235		)	—
Other, net	(3,433		)	1,232
Net cash flows from investing activities	(311,693		)	(211,426		)

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

9

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2014			2013
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(49,200		)	(46,700		)
Long-term borrowings	255,000			75,000
Repayment of long-term debt	(125,000		)	(26,037		)
Cash paid in debt exchange	—			(13,048		)
Proceeds from stock option exercise	5,495			3,500
Awards of common stock	(15,573		)	(12,429		)
Dividends paid	(44,600		)	(38,233		)
Valencia’s transactions with its owner	(12,749		)	(13,477		)
Other, net	(2,030		)	(3,706		)
Net cash flows from financing activities	11,343			(75,130		)
Change in Cash and Cash Equivalents	25,891			24,454
Cash and Cash Equivalents at Beginning of Period	2,533			8,985
Cash and Cash Equivalents at End of Period	$	28,424		$	33,439
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	60,075		$	63,985
Income taxes paid (refunded), net	$	(2,529	)	$	(95,472	)
Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(6,674	)	$	2,535
Premium on long-term debt incurred in connection with debt exchange	$	—		$	36,297

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

10

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2014		December 31, 2013
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	28,424	$	2,533
Accounts receivable, net of allowance for uncollectible accounts of $1,535 and $1,423	105,516		90,251
Unbilled revenues	63,253		58,806
Other receivables	39,061		53,909
Materials, supplies, and fuel stock	63,637		67,223
Regulatory assets	41,606		24,416
Commodity derivative instruments	4,148		4,064
Income taxes receivable	6,723		7,066
Current portion of accumulated deferred income taxes	58,681		58,681
Other current assets	55,277		34,590
Total current assets	466,326		401,539
Other Property and Investments:
Investment in PVNGS lessor notes	9,775		32,200
Available-for-sale securities	235,894		226,855
Other investments	1,667		1,835
Non-utility property	4,060		4,353
Total other property and investments	251,396		265,243
Utility Plant:
Plant in service and plant held for future use	5,754,564		5,563,061
Less accumulated depreciation and amortization	1,913,361		1,838,832
	3,841,203		3,724,229
Construction work in progress	211,472		132,080
Nuclear fuel, net of accumulated amortization of $52,119 and $47,347	81,840		77,602
Net utility plant	4,134,515		3,933,911
Deferred Charges and Other Assets:
Regulatory assets	479,138		523,955
Goodwill	278,297		278,297
Commodity derivative instruments	1,084		3,002
Other deferred charges	98,453		94,263
Total deferred charges and other assets	856,972		899,517
	$	5,709,209	$	5,500,210

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

11

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2014			December 31, 2013
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	100,000		$	149,200
Current installments of long-term debt	333,066			75,000
Accounts payable	102,656			109,666
Customer deposits	12,483			13,456
Accrued interest and taxes	82,052			49,600
Regulatory liabilities	1,126			1,081
Commodity derivative instruments	1,370			2,699
Dividends declared	14,868			14,864
Other current liabilities	52,671			77,105
Total current liabilities	700,292			492,671
Long-term Debt	1,542,106			1,670,420
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	884,402			801,408
Accumulated deferred investment tax credits	24,232			25,855
Regulatory liabilities	472,054			460,649
Asset retirement obligations	102,115			96,135
Accrued pension liability and postretirement benefit cost	69,363			80,046
Commodity derivative instruments	688			1,094
Other deferred credits	104,270			109,805
Total deferred credits and other liabilities	1,657,124			1,574,992
Total liabilities	3,899,522			3,738,083
Commitments and Contingencies (See Note 11)
Cumulative Preferred Stock of Subsidiary
without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529			11,529
Equity:
PNMR common stockholders’ equity:
Common stock outstanding (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,172,876			1,178,369
Accumulated other comprehensive income (loss), net of income taxes	(56,532		)	(58,140		)
Retained earnings	606,394			553,340
Total PNMR common stockholders’ equity	1,722,738			1,673,569
Non-controlling interest in Valencia	75,420			77,029
Total equity	1,798,158			1,750,598
	$	5,709,209		$	5,500,210

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

12

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

	Attributable to PNMR												Non- controlling Interest in Valencia
	Common Stock			AOCI			Retained Earnings			Total PNMR Common Stockholder’s Equity						Total Equity
	(In thousands)
Balance at December 31, 2013	$	1,178,369		$	(58,140	)	$	553,340		$	1,673,569		$	77,029		$	1,750,598
Proceeds from stock option exercise	5,495			—			—			5,495			—			5,495
Awards of common stock	(15,573		)	—			—			(15,573		)	—			(15,573		)
Excess tax (shortfall) from stock-based payment arrangements	(95		)	—			—			(95		)	—			(95		)
Stock based compensation expense	4,680			—			—			4,680			—			4,680
Valencia’s transactions with its owner	—			—			—			—			(12,749		)	(12,749		)
Net earnings before subsidiary preferred stock dividends	—			—			97,658			97,658			11,140			108,798
Subsidiary preferred stock dividends	—			—			(396		)	(396		)	—			(396		)
Total other comprehensive income	—			1,608			—			1,608			—			1,608
Dividends declared on common stock	—			—			(44,208		)	(44,208		)	—			(44,208		)
Balance at September 30, 2014	$	1,172,876		$	(56,532	)	$	606,394		$	1,722,738		$	75,420		$	1,798,158

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

13

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Electric Operating Revenues	$	334,993		$	326,026		$	873,434		$	863,609
Operating Expenses:
Cost of energy	115,097			100,200			304,365			283,715
Administrative and general	37,519			40,679			116,731			116,058
Energy production costs	43,287			41,142			136,422			131,546
Regulatory disallowances	—			1,735			—			1,735
Depreciation and amortization	27,524			25,879			81,629			77,763
Transmission and distribution costs	10,693			11,686			32,202			33,420
Taxes other than income taxes	10,258			9,488			30,359			28,613
Total operating expenses	244,378			230,809			701,708			672,850
Operating income	90,615			95,217			171,726			190,759
Other Income and Deductions:
Interest income	2,102			2,298			6,295			7,839
Gains on available-for-sale securities	962			2,188			8,234			6,935
Other income	1,804			2,398			5,359			5,329
Other (deductions)	(1,197		)	(2,375		)	(4,844		)	(5,287		)
Net other income and deductions	3,671			4,509			15,044			14,816
Interest Charges	20,092			20,124			59,927			59,971
Earnings before Income Taxes	74,194			79,602			126,843			145,604
Income Taxes	25,142			27,652			42,331			49,184
Net Earnings	49,052			51,950			84,512			96,420
(Earnings) Attributable to Valencia Non-controlling Interest	(3,701		)	(4,127		)	(11,140		)	(10,904		)
Net Earnings Attributable to PNM	45,351			47,823			73,372			85,516
Preferred Stock Dividends Requirements	(132		)	(132		)	(396		)	(396		)
Net Earnings Available for PNM Common Stock	$	45,219		$	47,691		$	72,976		$	85,120

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

14

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Net Earnings	$	49,052		$	51,950		$	84,512		$	96,420
Other Comprehensive Income:
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(137), $(4,143), $(3,946) and $(7,544)	210			6,322			6,256			11,512
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,059, $925, $4,547 and $3,639	(1,628		)	(1,411		)	(6,997		)	(5,551		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(508), $(631), $(1,524) and $(1,893)	780			960			2,340			2,880
Total Other Comprehensive Income (Loss)	(638		)	5,871			1,599			8,841
Comprehensive Income	48,414			57,821			86,111			105,261
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,701		)	(4,127		)	(11,140		)	(10,904		)
Comprehensive Income Attributable to PNM	$	44,713		$	53,694		$	74,971		$	94,357

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

15

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	84,512		$	96,420
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	108,069			104,161
Deferred income tax expense	45,313			49,870
Net unrealized (gains) on commodity derivatives	(67		)	(5,858		)
Realized (gains) on available-for-sale securities	(8,234		)	(6,935		)
Regulatory disallowances	—			1,735
Other, net	(355		)	(1,342		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(16,782		)	(14,123		)
Materials, supplies, and fuel stock	5,697			(744		)
Other current assets	(20,806		)	(5,187		)
Other assets	29,796			21,977
Accounts payable	10,100			(4,953		)
Accrued interest and taxes	19,984			66,090
Other current liabilities	(21,586		)	(43,935		)
Other liabilities	2,841			(67,062		)
Net cash flows from operating activities	238,482			190,114
Cash Flows From Investing Activities:
Utility plant additions	(199,771		)	(164,669		)
Proceeds from sales of available-for-sale securities	82,222			179,336
Purchases of available-for-sale securities	(81,644		)	(181,423		)
Return of principal on PVNGS lessor notes	20,758			23,357
Purchase of Rio Bravo	(36,235		)	—
Other, net	(3,404		)	1,234
Net cash flows from investing activities	(218,074		)	(142,165		)

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

16

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2014			2013
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(49,200		)	(21,100		)
Short-term borrowings (repayments), affiliate, net	(26,000		)	—
Long-term borrowings	175,000			75,000
Repayment of long-term debt	(75,000		)	—
Valencia’s transactions with its owner	(12,749		)	(13,477		)
Dividends paid	(30,659		)	(68,424		)
Other, net	(1,196		)	(1,727		)
Net cash flows from financing activities	(19,804		)	(29,728		)
Change in Cash and Cash Equivalents	604			18,221
Cash and Cash Equivalents at Beginning of Period	21			3,958
Cash and Cash Equivalents at End of Period	$	625		$	22,179
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	41,606		$	42,145
Income taxes paid (refunded), net	$	(215	)	$	(44,999	)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	$	(10,586	)	$	8,912

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

17

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2014		December 31, 2013
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	625	$	21
Accounts receivable, net of allowance for uncollectible accounts of $1,535 and $1,423	78,811		70,126
Unbilled revenues	54,643		48,992
Other receivables	38,799		52,964
Affiliate receivables	9,572		10,054
Materials, supplies, and fuel stock	60,731		64,520
Regulatory assets	38,328		19,394
Commodity derivative instruments	4,148		4,064
Income taxes receivable	6,797		4,030
Current portion of accumulated deferred income taxes	43,826		43,827
Other current assets	49,533		30,510
Total current assets	385,813		348,502
Other Property and Investments:
Investment in PVNGS lessor notes	9,775		32,200
Available-for-sale securities	235,894		226,855
Other investments	300		445
Non-utility property	752		976
Total other property and investments	246,721		260,476
Utility Plant:
Plant in service and plant held for future use	4,460,035		4,314,016
Less accumulated depreciation and amortization	1,469,375		1,402,531
	2,990,660		2,911,485
Construction work in progress	167,180		107,344
Nuclear fuel, net of accumulated amortization of $52,119 and $47,347	81,840		77,602
Net utility plant	3,239,680		3,096,431
Deferred Charges and Other Assets:
Regulatory assets	347,642		384,217
Goodwill	51,632		51,632
Commodity derivative instruments	1,084		3,002
Other deferred charges	85,902		83,356
Total deferred charges and other assets	486,260		522,207
	$	4,358,474	$	4,227,616

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

18

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2014			December 31, 2013
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	—		$	49,200
Short-term debt - affiliate	6,500			32,500
Current installments of long-term debt	214,300			75,000
Accounts payable	83,741			84,643
Affiliate payables	14,692			20,498
Customer deposits	12,483			13,456
Accrued interest and taxes	51,188			27,665
Regulatory liabilities	1,126			1,081
Commodity derivative instruments	1,370			2,699
Dividends declared	132			132
Other current liabilities	35,576			50,392
Total current liabilities	421,108			357,266
Long-term Debt	1,176,347			1,215,618
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	714,983			651,239
Accumulated deferred investment tax credits	24,232			25,855
Regulatory liabilities	425,062			414,611
Asset retirement obligations	101,147			95,225
Accrued pension liability and postretirement benefit cost	66,183			76,611
Commodity derivative instruments	688			1,094
Other deferred credits	87,264			91,340
Total deferred credits and liabilities	1,419,559			1,355,975
Total liabilities	3,017,014			2,928,859
Commitments and Contingencies (See Note 11)
Cumulative Preferred Stock
without mandatory redemption requirements ($100 stated value; 10,000,000 authorized; issued and outstanding 115,293 shares)	11,529			11,529
Equity:
PNM common stockholder’s equity:
Common stock outstanding (no par value; 40,000,000 shares authorized; issued and outstanding 39,117,799 shares)	1,061,776			1,061,776
Accumulated other comprehensive income (loss), net of income taxes	(56,278		)	(57,877		)
Retained earnings	249,013			206,300
Total PNM common stockholder’s equity	1,254,511			1,210,199
Non-controlling interest in Valencia	75,420			77,029
Total equity	1,329,931			1,287,228
	$	4,358,474		$	4,227,616

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

19

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

	Attributable to PNM
									Total PNM Common Stockholder’s Equity			Non- controlling  Interest in Valencia
	Common Stock		AOCI			Retained Earnings									Total Equity
	(In thousands)
Balance at December 31, 2013	$	1,061,776	$	(57,877	)	$	206,300		$	1,210,199		$	77,029		$	1,287,228
Valencia’s transactions with its owner	—		—			—			—			(12,749		)	(12,749		)
Net earnings	—		—			73,372			73,372			11,140			84,512
Total other comprehensive income	—		1,599			—			1,599			—			1,599
Dividends declared on preferred stock	—		—			(396		)	(396		)	—			(396		)
Dividends declared on common stock	—		—			(30,263		)	(30,263		)	—			(30,263		)
Balance at September 30, 2014	$	1,061,776	$	(56,278	)	$	249,013		$	1,254,511		$	75,420		$	1,329,931

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

20

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Electric Operating Revenues	$	78,958		$	73,704		$	215,574		$	201,384
Operating Expenses:
Cost of energy	17,402			14,474			50,167			41,324
Administrative and general	9,230			10,641			27,839			32,446
Depreciation and amortization	13,432			13,850			37,276			37,810
Transmission and distribution costs	6,191			5,562			17,655			17,270
Taxes other than income taxes	6,830			6,923			18,238			17,558
Total operating expenses	53,085			51,450			151,175			146,408
Operating income	25,873			22,254			64,399			54,976
Other Income and Deductions:
Other income	1,072			820			2,078			1,765
Other (deductions)	(279		)	(104		)	(583		)	(356		)
Net other income and deductions	793			716			1,495			1,409
Interest Charges	6,870			6,655			20,122			20,661
Earnings before Income Taxes	19,796			16,315			45,772			35,724
Income Taxes	7,441			6,209			17,081			13,554
Net Earnings	$	12,355		$	10,106		$	28,691		$	22,170

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

21

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Net Earnings	$	12,355		$	10,106		$	28,691		$	22,170
Other Comprehensive Income (Loss):
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0 $128, $53 and $127	—			(238		)	(100		)	(236		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $3, $(19), $(58) and $(54)	(6		)	35			109			99
Total Other Comprehensive Income (Loss)	(6		)	(203		)	9			(137		)
Comprehensive Income	$	12,349		$	9,903		$	28,700		$	22,033

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

22

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	28,691		$	22,170
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	39,577			40,946
Deferred income tax expense	4,256			3,901
Other, net	(169		)	(13		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(5,376		)	(9,608		)
Materials and supplies	(203		)	20
Other current assets	1,761			(2,420		)
Other assets	(58		)	36
Accounts payable	(1,302		)	(291		)
Accrued interest and taxes	19,054			14,669
Other current liabilities	(1,217		)	(1,946		)
Other liabilities	1,397			2,182
Net cash flows from operating activities	86,411			69,646
Cash Flows From Investing Activities:
Utility plant additions	(88,940		)	(67,400		)
Net cash flows from investing activities	(88,940		)	(67,400		)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	—			12,000
Short-term borrowings (repayments) – affiliate, net	(10,300		)	4,800
Long-term borrowings	80,000			—
Repayment of long-term debt	(50,000		)	—
Cash paid in debt exchange	—			(13,048		)
Dividends paid	(16,336		)	(3,726		)
Other, net	(835		)	(2,117		)
Net cash flows from financing activities	2,529			(2,091		)
Change in Cash and Cash Equivalents	—			155
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	1		$	156
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	11,778		$	13,626
Income taxes paid (refunded), net	$	(299	)	$	696
Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	1,658		$	(1,443	)
Premium on long-term debt incurred in connection with debt exchange	$	—		$	36,297

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

23

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2014		December 31, 2013
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable	26,705		20,125
Unbilled revenues	8,610		9,814
Other receivables	679		1,246
Materials and supplies	2,906		2,703
Regulatory assets	3,278		5,022
Current portion of accumulated deferred income taxes	6,501		6,501
Other current assets	1,672		980
Total current assets	50,352		46,392
Other Property and Investments:
Other investments	245		245
Non-utility property	2,240		2,240
Total other property and investments	2,485		2,485
Utility Plant:
Plant in service and plant held for future use	1,127,872		1,074,193
Less accumulated depreciation and amortization	369,426		352,105
	758,446		722,088
Construction work in progress	36,841		16,790
Net utility plant	795,287		738,878
Deferred Charges and Other Assets:
Regulatory assets	131,496		139,738
Goodwill	226,665		226,665
Other deferred charges	10,260		8,273
Total deferred charges and other assets	368,421		374,676
	$	1,216,545	$	1,162,431

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

24

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2014			December 31, 2013
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt – affiliate	$	19,100		$	29,400
Accounts payable	9,584			12,543
Affiliate payables	1,758			3,181
Accrued interest and taxes	42,831			23,778
Other current liabilities	2,491			8,999
Total current liabilities	75,764			77,901
Long-term Debt	365,759			336,036
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	201,441			190,197
Regulatory liabilities	46,992			46,038
Asset retirement obligations	831			782
Accrued pension liability and postretirement benefit cost	3,180			3,435
Other deferred credits	7,283			5,111
Total deferred credits and other liabilities	259,727			245,563
Total liabilities	701,250			659,500
Commitments and Contingencies (See Note 11)
Common Stockholder’s Equity:
Common stock outstanding ($10 par value; 12,000,000 shares authorized;
issued and outstanding 6,358 shares)	64			64
Paid-in-capital	404,166			404,166
Accumulated other comprehensive income (loss), net of income taxes	(254		)	(263		)
Retained earnings	111,319			98,964
Total common stockholder’s equity	515,295			502,931
	$	1,216,545		$	1,162,431

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

25

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCKHOLDER’S EQUITY

(Unaudited)

	Common Stock		Paid-in Capital		AOCI			Retained Earnings			Total Common Stockholder’s Equity
	(In thousands)
Balance at December 31, 2013	$	64	$	404,166	$	(263	)	$	98,964		$	502,931
Net earnings	—		—		—			28,691			28,691
Total other comprehensive income	—		—		9			—			9
Dividends declared on common stock	—		—		—			(16,336		)	(16,336		)
Balance at September 30, 2014	$	64	$	404,166	$	(254	)	$	111,319		$	515,295

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

26

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Significant Accounting Policies and Responsibility for Financial Statements

Financial Statement Preparation

In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at September 30, 2014 and December 31, 2013, the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the consolidated cash flows for the nine months ended September 30, 2014 and 2013. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.

The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are so indicated. Certain amounts in the 2013 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2014 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s, and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2013 Annual Reports on Form 10-K.

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

Principles of Consolidation

The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM began consolidating Rio Bravo, formerly known as Delta, upon its acquisition on July 17, 2014. PNM also consolidates the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 14.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.185 per share in July 2014 and $0.165 in July

27

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2013, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. The Board declared dividends on common stock considered to be for the third quarter of $0.185 per share in September 2014 and $0.165 in September 2013, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

PNM declared and paid cash dividends on its common stock to PNMR of $30.3 million and $68.0 million in the nine months ended September 30, 2014 and 2013. TNMP declared and paid cash dividends of $16.3 million and $3.7 million in the nine months ended September 30, 2014 and 2013.

New Accounting Pronouncements

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

Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606)

On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for the Company beginning on January 1, 2017. Early adoption is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

Accounting Standards Update 2014-12 – Compensation-Stock Compensation (Topic 718) Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period

On June 19, 2014, the FASB issued ASU No. 2014-12, which requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in estimating the grant date fair value of the award. The new standard is effective for the Company beginning on January 1, 2016. Early adoption is permitted and the standard permits the use of either the prospective or retrospective transition methods. Although the Company is in the process of analyzing the impacts this new standard will have on its consolidated financial statements, the Company currently treats the performance targets covered by the standard as performance conditions, so the Company does not expect its impact will be significant.

Accounting Standards Update 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

On August 27, 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company is in the process of analyzing the impacts of this new standard .

28

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(2) Earnings Per Share

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	55,653	$	54,555	$	97,262	$	92,859
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	112		177		134		194
Average Shares – Basic	79,766		79,831		79,788		79,848
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	457		503		491		608
Average Shares – Diluted	80,223		80,334		80,279		80,456
Net Earnings Per Share of Common Stock:
Basic	$	0.70	$	0.68	$	1.22	$	1.16
Diluted	$	0.69	$	0.68	$	1.21	$	1.15

⁽¹⁾  Excludes the effect of out-of-the-money options for 435,472 shares of common stock at September 30, 2014.

(3) Segment Information

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

PNM

PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also provides generation service to firm-requirements wholesale customers and sells electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM’s jurisdictional capacity, as well as the capacity from PVNGS Unit 3, which currently is not included in retail rates. FERC has jurisdiction over wholesale and transmission rates.

TNMP

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

Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company.

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

29

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNMR SEGMENT INFORMATION

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2014
Electric operating revenues	$	334,993		$	78,958		$	—		$	413,951
Cost of energy	115,097			17,402			—			132,499
Margin	219,896			61,556			—			281,452
Other operating expenses	101,757			22,251			(3,650		)	120,358
Depreciation and amortization	27,524			13,432			3,339			44,295
Operating income	90,615			25,873			311			116,799
Interest income	2,102			—			(18		)	2,084
Other income (deductions)	1,569			793			(589		)	1,773
Net interest charges	(20,092		)	(6,870		)	(3,153		)	(30,115		)
Segment earnings (loss) before income taxes	74,194			19,796			(3,449		)	90,541
Income taxes (benefit)	25,142			7,441			(1,528		)	31,055
Segment earnings (loss)	49,052			12,355			(1,921		)	59,486
Valencia non-controlling interest	(3,701		)	—			—			(3,701		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	45,219		$	12,355		$	(1,921	)	$	55,653
Nine Months Ended September 30, 2014
Electric operating revenues	$	873,434		$	215,574		$	—		$	1,089,008
Cost of energy	304,365			50,167			—			354,532
Margin	569,069			165,407			—			734,476
Other operating expenses	315,714			63,732			(10,243		)	369,203
Depreciation and amortization	81,629			37,276			9,519			128,424
Operating income	171,726			64,399			724			236,849
Interest income	6,295			—			(54		)	6,241
Other income (deductions)	8,749			1,495			(1,547		)	8,697
Net interest charges	(59,927		)	(20,122		)	(9,572		)	(89,621		)
Segment earnings (loss) before income taxes	126,843			45,772			(10,449		)	162,166
Income taxes (benefit)	42,331			17,081			(6,044		)	53,368
Segment earnings (loss)	84,512			28,691			(4,405		)	108,798
Valencia non-controlling interest	(11,140		)	—			—			(11,140		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	72,976		$	28,691		$	(4,405	)	$	97,262
At September 30, 2014:
Total Assets	$	4,358,474		$	1,216,545		$	134,190		$	5,709,209
Goodwill	$	51,632		$	226,665		$	—		$	278,297

30

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

31

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(4) Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2014 and 2013 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	Unrealized						Fair Value
	Gain on			Pension			Adjustment
	Available-for-			Liability			for Cash Flow
	Sale Securities			Adjustment			Hedges			Total
	(In thousands)
PNMR
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(263	)	$	(58,140	)
Amounts reclassified from AOCI (pre-tax)	(11,544		)	3,864			167			(7,513		)
Income tax impact of amounts reclassified	4,547			(1,524		)	(58		)	2,965
Other OCI changes (pre-tax)	10,202			—			(153		)	10,049
Income tax impact of other OCI changes	(3,946		)	—			53			(3,893		)
Net change after income taxes	(741		)	2,340			9			1,608
Balance at September 30, 2014	$	25,007		$	(81,285	)	$	(254	)	$	(56,532	)

PNM
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	—	$	(57,877	)
Amounts reclassified from AOCI (pre-tax)	(11,544		)	3,864			—		(7,680		)
Income tax impact of amounts reclassified	4,547			(1,524		)	—		3,023
Other OCI changes (pre-tax)	10,202			—			—		10,202
Income tax impact of other OCI changes	(3,946		)	—			—		(3,946		)
Net change after income taxes	(741		)	2,340			—		1,599
Balance at September 30, 2014	$	25,007		$	(81,285	)	$	—	$	(56,278	)

TNMP
Balance at December 31, 2013	$	—	$	—	$	(263	)	$	(263	)
Amounts reclassified from AOCI (pre-tax)	—		—		167			167
Income tax impact of amounts reclassified	—		—		(58		)	(58		)
Other OCI changes (pre-tax)	—		—		(153		)	(153		)
Income tax impact of other OCI changes	—		—		53			53
Net change after income taxes	—		—		9			9
Balance at September 30, 2014	$	—	$	—	$	(254	)	$	(254	)

32

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

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

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

Pre-tax amounts reclassified from AOCI related to “Unrealized Gain on Available-for-Sale Securities” are included in “Gains on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “Pension Liability Adjustment” are reclassified to “Operating Expenses – Administrative and general” in the Condensed Consolidated Statements of Earnings. For the nine months ended September 30, 2014 and 2013, approximately 23.6% and 19.6% of the amount reclassified was capitalized into construction work in process and approximately 1.7% and 1.1% was capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes” in the Condensed Consolidated Statements of Earnings.

33

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(5) Variable Interest Entities; Acquisition

GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. Additional information concerning PNM’s variable interest entities is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Valencia

PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and nine months ended September 30, 2014, PNM paid $4.8 million and $14.4 million for fixed charges and $0.3 million and $1.0 million for variable charges. For the three and nine months ended September 30, 2013, PNM paid $4.8 million and $14.1 million for fixed charges and $0.7 million and $1.0 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM has concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates the entity in its financial statements. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Operating revenues	$	5,061		$	5,453		$	15,300		$	15,150
Operating expenses	(1,360		)	(1,326		)	(4,160		)	(4,246		)
Earnings attributable to non-controlling interest	$	3,701		$	4,127		$	11,140		$	10,904

Financial Position

	September 30,		December 31,
	2014		2013
	(In thousands)
Current assets	$	3,435	$	2,658
Net property, plant, and equipment	73,024		75,137
Total assets	76,459		77,795
Current liabilities	1,039		766
Owners’ equity – non-controlling interest	$	75,420	$	77,029

During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity. The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii)

34

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

50% of fair market value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process was initiated since the parties failed to reach agreement on fair market value within 60 days. Under the PPA, results of the appraisal process established the purchase price, after which PNM was to determine, in its sole discretion, whether or not to exercise its option to purchase the 50% interest. The PPA also provides that the purchase price may be adjusted to reflect the period between the determination of the purchase price and the closing. The appraisal process determined the purchase price as of October 8, 2013 to be $85.0 million, prior to any adjustment to reflect the period through the closing date. Approval of the purchase by the NMPRC and FERC would be required, which process could take in excess of 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. PNM is discussing these issues with the owner of Valencia. PNM cannot predict whether or not it will reach agreement with the owner of Valencia, if required regulatory and other approvals will be received, or if the purchase will be completed.

PVNGS Leases

PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. PNM is not the legal or tax owner of the leased assets. The leases provide PNM with an option to purchase the leased assets at appraised value at the end of the leases. PNM does not have a fixed price purchase option and does not provide residual value guarantees. The leases also provide PNM with options to renew the leases at fixed rates set forth in the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K and Note 6, for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities.

PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments. As of September 30, 2014, these payments aggregate $20.3 million, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, over the remaining original terms of the leases and $145.2 million during the renewal terms of the leases that PNM elected to renew. Under certain circumstances (for example, final shutdown of the plant, the NRC issuing specified violation orders with respect to PVNGS, or the occurrence of specified nuclear events), PNM would be required to make specified payments to the beneficial owners and take title to the leased interests. If such an event had occurred as of September 30, 2014, PNM could have been required to pay the beneficial owners up to $123.8 million, which would result in PNM taking ownership of the leased assets and termination of the leases. Other than as discussed in Note 6, PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets.

PNM has evaluated the PVNGS lease arrangements, including the notices, amendments, and agreements referred to above, and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP. PNM has recorded no assets or liabilities related to the trusts other than the accrual of lease payments between the scheduled payment dates, which were $11.8 million at September 30, 2014 and $26.0 million at December 31, 2013, that are included in other current liabilities on the Condensed Consolidated Balance Sheets.

Rio Bravo, formerly known as Delta

PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which was a variable interest under GAAP. PNM also controlled the dispatch of the generating plant, which impacted the variable payments made under the PPA and impacted the economic performance of the entity that owned Delta. This arrangement was entered into prior to December 31, 2003 and

35

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM was unsuccessful in obtaining the information necessary to determine if it was the primary beneficiary of the entity that owned Delta, or to consolidate that entity if it were determined that PNM was the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.

In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owned Delta. FERC approved the purchase on February 26, 2013 and the NMPRC approved the purchase on June 26, 2013. Closing was subject to the seller remedying specified operational, NERC compliance, and environmental issues, as well as other customary closing conditions. PNM closed on the purchase on July 17, 2014 and recorded the purchase as of that date. At closing, PNM made a cash payment of $22.8 million, which reflected an adjustment for working capital compared to a targeted working capital and included amounts placed in escrow. Delta had project financing debt, which PNM retired at closing of the purchase, amounting to $14.6 million at closing. Subsequent to closing, PNM changed the name of the facility to Rio Bravo.

PNM recorded the acquisition as a business combination and reflected the requirements of the FERC Uniform System of Accounts since the purchased assets are subject to traditional rate regulation by the NMPRC and FERC. Accordingly, as of the acquisition date, PNM recorded plant in service of $58.1 million and accumulated depreciation of $23.5 million, reflecting the original cost of the facilities and the estimated economic life to PNM. PNM also recorded current assets of $3.6 million, deferred charges of $3.4 million, current liabilities of $0.3 million, and non-current regulatory liabilities of $3.4 million.

PNM made fixed and variable payments to Delta under the PPA. For the periods from July 1, 2014 through July 17, 2014 and January 1, 2014 through July 17, 2014, PNM incurred fixed capacity charges of $0.3 million and $3.5 million and variable energy charges of $0.1 million and $0.6 million under the PPA. For the three and nine months ended September 30, 2013, PNM incurred fixed capacity charges of $1.6 million and $4.8 million and variable energy charges of $0.7 million and $1.3 million. PNM recovered the variable energy charges through its FPPAC.

PNM began consolidating Rio Bravo at the date of the acquisition. Prior to the acquisition, consolidation of Delta would have been immaterial to the Condensed Consolidated Balance Sheets of PNMR and PNM. Since all of Delta’s revenues and expenses were attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Condensed Consolidated Statements of Earnings of PNMR and PNM would have been to reclassify Delta’s net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM.

(6) Lease Commitments

The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS and an interest in the EIP transmission line. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. Each of the leases provides PNM with an option to purchase the leased assets at fair market value at the end of the lease. In addition, the leases provide PNM with options to renew the leases at fixed rates set forth in each of the leases for two years beyond the termination of the original lease terms. The option periods on certain leases could be further extended for up to an additional six years (the “Maximum Option Period”) if the appraised remaining useful lives and fair values of the leased assets are greater than parameters set forth in the leases. The rental payments during the renewal option periods would be 50% of the amounts during the original terms of the leases.

Following procedures set forth in the PVNGS leases, PNM notified each of the lessors under the Unit 1 leases that it would elect to renew those leases for the Maximum Option Period on the expiration date of the original leases. In addition, PNM notified the lessor under the one Unit 2 lease containing the Maximum Option Period provision that it would elect to renew that lease for the Maximum Option Period on the expiration date of the original lease. On December 11, 2013, PNM and each of the Unit 1 lessors entered into amendments to each of the Unit 1 leases setting forth the terms and conditions that will implement the extension of the term of the lease through the agreed upon Maximum Option Period expiring on January 15, 2023. Similarly, on March 18, 2014, PNM and the lessor under the one Unit 2 lease containing the Maximum Option Period provision entered into an amendment

36

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

to that lease setting forth the terms and conditions that will implement the extension of the term of the lease through the agreed upon Maximum Option Period expiring on January 15, 2024.

For the three PVNGS Unit 2 leases which do not contain the Maximum Option Period provisions, PNM, following procedures set forth in the leases, notified each of the lessors that PNM would elect to purchase the assets underlying those leases on the expiration date of the original leases. On February 25, 2014, PNM and the lessor under one of the Unit 2 leases entered into a letter agreement that establishes that the purchase price, representing the fair market value, to be paid by PNM for the assets underlying that lease will be $78.1 million on January 15, 2016. This lease is for 31.25 MW of the entitlement from PVNGS Unit 2. The lease remains in existence and PNM will record the purchase at the termination of the lease on January 15, 2016.

On May 1, 2014, PNM and the trusts that are the lessors under the other two PVNGS Unit 2 leases signed a letter agreement that establishes a binding agreement regarding the purchase price, representing the fair market value, to be paid by PNM for the assets underlying those leases of $85.2 million on January 15, 2016. These leases are for 32.76 MW of the entitlement from PVNGS Unit 2. PNMR Development, a wholly-owned subsidiary of PNMR, is also a party to the letter agreement, which constitutes a letter of intent providing PNMR Development with the option, subject to approval by the Board and negotiation of definitive documents, to acquire the entities that own the leased assets at any time from June 1, 2014 through January 14, 2016. The early purchase price would be equal to the January 15, 2016 purchase price discounted to the actual purchase date. The early purchase amount was $79.9 million on June 1, 2014 and escalates to $85.2 million on January 14, 2016. The consideration paid to the lessor on an early purchase would include an additional amount equal to the discounted value of the lessors’ equity return portion of the future lease payments. Such additional consideration was $5.8 million on June 1, 2014 and declines to $1.2 million on January 14, 2016. PNMR and PNM are unable to predict whether or not the early purchase will occur.

(7) Fair Value of Derivative and Other Financial Instruments

Energy Related Derivative Contracts

Overview

The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. The Company’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. Additional information concerning the Company’s energy related derivative contracts, including how commodity risk is managed, is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Commodity Risk

Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.

Accounting for Derivatives

Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. Energy contracts that meet the definition of a

37

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

During the nine months ended September 30, 2014 and the year ended December 31, 2013, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. The Company has no trading transactions.

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

Commodity Derivatives

Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows:

	Economic Hedges
	September 30, 2014			December 31, 2013
PNMR and PNM	(In thousands)
Current assets	$	4,148		$	4,064
Deferred charges	1,084			3,002
	5,232			7,066
Current liabilities	(1,370		)	(2,699		)
Long-term liabilities	(688		)	(1,094		)
	(2,058		)	(3,793		)
Net	$	3,174		$	3,273

Included in the above table are $3.0 million of current assets and $0.8 million of deferred charges at September 30, 2014 and $3.0 million of current assets and $3.0 million of deferred charges at December 31, 2013 related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at September 30, 2014 and December 31, 2013.

At September 30, 2014 and December 31, 2013, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at September 30, 2014 and December 31, 2013, amounts posted as cash collateral under margin

38

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

arrangements were $2.4 million and $2.8 million for both PNMR and PNM. PNMR and PNM had obligations to return cash collateral of $0.2 million at September 30, 2014 and $0.2 million at December 31, 2013. Cash collateral amounts are included in other current assets and other current liabilities on the Condensed Consolidated Balance Sheets.

PNM has a NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.2 million of current assets and $0.1 million of current liabilities at September 30, 2014 and $0.4 million of current assets and $0.1 million of current liabilities at December 31, 2013 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.

The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.

	Economic Hedges
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
PNMR and PNM	(In thousands)
Electric operating revenues	$	2,352		$	7,077		$	(2,124	)	$	5,743
Cost of energy	(60		)	(72		)	186			421
Total gain (loss)	$	2,292		$	7,005		$	(1,938	)	$	6,164

Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:

	Economic Hedges
	MMBTU	MWh
September 30, 2014
PNMR and PNM	656,000	(2,511,371	)
December 31, 2013
PNMR and PNM	905,000	(3,343,783	)

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

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

39

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
September 30, 2014
PNMR and PNM	$	1,532	$	—	$	1,403
December 31, 2013
PNMR and PNM	$	2,398	$	—	$	2,152

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not included in retail rates, that unit’s power is being sold in the wholesale market. Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of September 30, 2014, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium.  PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales through the end of 2014 through hedging arrangements that are accounted for as economic hedges. PNM is also partially hedged for 2015.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and a trust for PNM’s share of post-term reclamation costs related to the coal mines that serve SJGS (Note 11). The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table. At September 30, 2014 and December 31, 2013, the fair value of available-for-sale securities included $231.4 million and $222.5 million for the NDT and $4.5 million and $4.4 million for the mine reclamation trust.

	September 30, 2014				December 31, 2013
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,338	$	—	$	3,356
Equity securities:
Domestic value	15,360		41,917		14,523		39,460
Domestic growth	18,452		74,647		25,656		76,292
International and other	1,339		16,957		1,040		16,633
Fixed income securities:
U.S. Government	520		19,616		158		21,941
Municipals	4,970		67,595		1,018		58,568
Corporate and other	631		11,824		207		10,605
	$	41,272	$	235,894	$	42,602	$	226,855

40

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold and reflect impairments.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(In thousands)
Proceeds from sales	$	29,103		$	103,230		$	82,222		$	179,336
Gross realized gains	$	3,134		$	2,719		$	11,616		$	8,962
Gross realized (losses)	$	(2,172	)	$	(531	)	$	(3,382	)	$	(2,027	)

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

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

At September 30, 2014, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR		PNM
	(In thousands)
Within 1 year	$	3,601	$	7,994	$	7,994
After 1 year through 5 years	20,886		25,456		24,718
After 5 years through 10 years	11,561		—		—
After 10 years through 15 years	9,549		—		—
After 15 years through 20 years	11,313		—		—
After 20 years	42,125		—		—
	$	99,035	$	33,450	$	32,712

Fair Value Disclosures

The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models.

For available-for-sale securities, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For the Company’s long-term debt, Level 2 fair values are provided by an external pricing service.

41

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at September 30, 2014 and December 31, 2013 for items recorded at fair value.

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2014	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,338		$	3,338	$	—
Equity securities:
Domestic value	41,917			41,917		—
Domestic growth	74,647			74,647		—
International and other	16,957			16,957		—
Fixed income securities:
U.S. Government	19,616			17,865		1,751
Municipals	67,595			—		67,595
Corporate and other	11,824			2,544		9,280
	$	235,894		$	157,268	$	78,626
Commodity derivative assets	$	5,232		$	—	$	5,232
Commodity derivative liabilities	(2,058		)	—		(2,058		)
Net	$	3,174		$	—	$	3,174
December 31, 2013
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,356		$	3,356	$	—
Equity securities:
Domestic value	39,460			39,460		—
Domestic growth	76,292			76,292		—
International and other	16,633			16,633		—
Fixed income securities:
U.S. Government	21,941			20,194		1,747
Municipals	58,568			—		58,568
Corporate and other	10,605			2,245		8,360
	$	226,855		$	158,180	$	68,675
Commodity derivative assets	$	7,066		$	—	$	7,066
Commodity derivative liabilities	(3,793		)	—		(3,793		)
Net	$	3,273		$	—	$	3,273

42

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:

					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
September 30, 2014	(In thousands)
PNMR
Long-term debt	$	1,875,172	$	2,072,872	$	—	$	2,072,872	$	—
Investment in PVNGS lessor notes	$	31,469	$	32,712	$	—	$	—	$	32,712
Other investments	$	1,667	$	2,406	$	546	$	—	$	1,860
PNM
Long-term debt	$	1,390,647	$	1,525,625	$	—	$	1,525,625	$	—
Investment in PVNGS lessor notes	$	31,469	$	32,712	$	—	$	—	$	32,712
Other investments	$	300	$	300	$	300	$	—	$	—
TNMP
Long-term debt	$	365,759	$	422,583	$	—	$	422,583	$	—
Other investments	$	245	$	245	$	245	$	—	$	—
December 31, 2013
PNMR
Long-term debt	$	1,745,420	$	1,905,230	$	—	$	1,905,230	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279
Other investments	$	1,835	$	3,196	$	690	$	—	$	2,506
PNM
Long-term debt	$	1,290,618	$	1,382,938	$	—	$	1,382,938	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279
Other investments	$	445	$	445	$	445	$	—	$	—
TNMP
Long-term debt	$	336,036	$	390,814	$	—	$	390,814	$	—
Other investments	$	245	$	245	$	245	$	—	$	—

The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the nine months ended September 30, 2014 and the year ended December 31, 2013.

(8) Stock-Based Compensation

PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets and some of these awards also have time vesting requirements. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 13 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, the awards vest ratably over three years from the grant date of the award. However, certain awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards.

The stock-based compensation expense related to stock options and restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However,

43

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

compensation expense for awards to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for performance-based shares is recognized ratably over the performance period and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At September 30, 2014 and December 31, 2013, PNMR had unrecognized expense related to stock awards of $7.9 million and $4.6 million. 

The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period.

The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:

	Nine Months Ended September 30,
Restricted Shares and Performance Based Shares	2014			2013
Expected quarterly dividends per share	$	0.185		$	0.165
Risk-free interest rate	0.62		%	0.34		%
Market-Based Shares
Dividend yield	2.82		%	2.86		%
Expected volatility	25.11		%	25.11		%
Risk-free interest rate	0.64		%	0.36		%

The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the nine months endedSeptember 30, 2014:

	Stock Option Shares		Weighted- Average Exercise Price		Restricted Stock		Weighted- Average Grant Date Fair Value
Outstanding at beginning of period	1,343,666		$	20.63	315,305		$	17.87
Granted	—		$	—	242,164		$	21.27
Exercised	(287,075	)	$	19.00	(295,423	)	$	16.68
Forfeited	(38,534	)	$	27.59	(515	)	$	24.74
Expired	(17,151	)	$	26.43	—		$	—
Outstanding at end of period	1,000,906		$	20.73	261,531		$	22.31

Included as restricted stock granted and exercised in the table above are 112,864 shares that were based upon achieving performance or market targets for 2013. The Board approved these shares in February 2014 (based upon achieving market targets, weighted at 60%, at maximum levels, and performance targets, weighted at 40%, at below threshold levels for the 2011 through 2013 performance period).

PNMR’s stock-based compensation program provides for performance or market targets through 2016. Excluded from the above table are maximums of 198,369, 179,811, and 175,735 restricted stock shares for periods ending in 2014, 2015, and 2016 that would be awarded if all performance or market criteria are achieved and all executives remain eligible.

44

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR’s common stock if the Company meets specific market targets at the end of 2016 and she remains an employee of the Company. If the Company achieves specific market targets at the end of 2014 and, with certain exceptions, she remains an employee of the Company, she would receive 35,000 of the total shares at that time. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include any restricted stock shares under the retention award agreement.

At September 30, 2014, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.2 million with a weighted-average remaining contract life of 2.98 years. At September 30, 2014, the exercise price of 435,472 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

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

	Nine Months Ended September 30,
Stock Options	2014		2013
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	625
Total intrinsic value of options exercised (in thousands)	$	2,199	$	2,466
Restricted Stock
Weighted-average grant date fair value	$	21.27	$	20.03
Total fair value of restricted shares that vested (in thousands)	$	4,929	$	4,395

(9) Financing

Additional information concerning financing activities, including a TNMP cash-flow hedge, which terminated on June 27, 2014, that established a fixed interest rate on a variable rate loan, is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Financing Activities

On January 8, 2014, PNM entered into a new $50.0 million unsecured revolving credit facility (the “PNM New Mexico Credit Facility”) by and among PNM, the lenders identified therein, U.S. Bank National Association, as Administrative Agent, and BOKF, NA dba Bank of Albuquerque, as Syndication Agent. The nine participating lenders are all banks that have a significant presence in New Mexico and PNM’s service territory or are headquartered in New Mexico. The PNM New Mexico Credit Facility expires on January 8, 2018 and contains covenants and conditions similar to those in the PNM Revolving Credit Facility.

On March 5, 2014, PNM entered into a new $175.0 million Term Loan Agreement (the “PNM 2014 Term Loan Agreement”) among PNM and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Lender and Administrative Agent. On March 5, 2014, PNM used a portion of the funds borrowed under the PNM 2014 Term Loan Agreement to repay all amounts outstanding under PNM’s existing $75.0 million PNM Term Loan Agreement. PNM also used the funds to repay other short-term amounts outstanding. The PNM Term Loan Agreement would otherwise have terminated on October 21, 2014. There were no prepayment penalties paid in connection with the termination of the PNM Term Loan Agreement. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.10% at September 30, 2014, must be repaid on or before September 4, 2015, and is reflected in current maturities of long-term debt on the Condensed Consolidated Balance Sheets. The PNM 2014 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNM 2014 Term Loan Agreement has a cross default provision and a change of control provision.

45

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On December 9, 2013, TNMP entered into an agreement (the “TNMP 2013 Bond Purchase Agreement”), which provided that TNMP would issue $80.0 million aggregate principal amount of 4.03% first mortgage bonds, due 2024 (the “Series 2014A Bonds”) on or about June 27, 2014, subject to satisfaction of certain conditions. TNMP issued the Series 2014A Bonds on June 27, 2014. TNMP used $50.0 million of the proceeds to repay the full outstanding amount of the TNMP 2011 Term Loan Agreement and used the remaining $30.0 million of proceeds to reduce short-term debt. In accordance with GAAP, borrowings under the TNMP 2011 Term Loan Agreement were reflected as being long-term at December 31, 2013 since the TNMP 2013 Bond Purchase Agreement demonstrated TNMP’s ability and intent to re-finance the TNMP 2011 Term Loan Agreement on a long-term basis.

Short-term Debt

PNMR has a revolving credit financing capacity of $300.0 million under the PNMR Revolving Credit Facility. PNM has a revolving credit financing capacity of $400.0 million under the PNM Revolving Credit Facility. Both of these facilities currently expire on October 31, 2018. TNMP has a revolving credit financing capacity of $75.0 million under the TNMP Revolving Credit Facility that is secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds and matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At September 30, 2014, there were no borrowings under any of these facilities. At September 30, 2014, PNM had $6.5 million and TNMP had $19.1 million in borrowings from PNMR under their intercompany loan agreements. At September 30, 2014, the weighted average interest rate was 1.01% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2014. Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2014		2013
	(In thousands)
PNM:
Revolving credit facility	$	—	$	49,200
PNM New Mexico Credit Facility	—		—
TNMP – Revolving credit facility	—		—
PNMR:
Revolving credit facility	—		—
PNMR Term Loan Agreement	100,000		100,000
	$	100,000	$	149,200

At October 24, 2014, PNMR, PNM, and TNMP had $292.3 million, $396.8 million, and $74.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $50.0 million of availability under the PNM New Mexico Credit Facility. Total availability at October 24, 2014, on a consolidated basis, was $814.0 million for PNMR. As of October 24, 2014, PNM had $7.4 million and TNMP had $25.7 million in borrowings from PNMR under their intercompany loan agreements. At October 24, 2014, PNMR, PNM and TNMP had consolidated invested cash of $23.1 million, none, and none.

(10) Pension and Other Postretirement Benefit Plans

PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans.

Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. The Society of Actuaries recently issued revised mortality tables that include changes in assumptions to reflect increased life expectancy and the corresponding decrease in mortality rates.  This change will have impacts on the Company’s pension plans, as the mortality assumptions are used as the basis for stating the pension obligation in financial statements, determining funding requirements,

46

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

and making minimum lump-sum calculations.  The Company, with the assistance of its consulting actuaries, is studying the impact of the mortality table changes.  This study is on-going and subject to change.  Preliminary estimates indicate that the Company’s pension liabilities reflecting the new mortality tables and other current assumptions could increase by approximately 7% over those previously reported.  Although pension expense and funding requirements also will likely increase, these changes are not expected to be material.

PNM Plans

The following tables present the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	45		$	65		$	—	$	—
Interest cost	7,541			7,035			1,159			1,029			205		180
Expected return on plan assets	(9,511		)	(10,482		)	(1,410		)	(1,261		)	—		—
Amortization of net (gain) loss	3,255			3,710			556			1,061			52		58
Amortization of prior service cost	(241		)	19			(336		)	(336		)	—		—
Net periodic benefit cost	$	1,044		$	282		$	14		$	558		$	257	$	238
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	136		$	195		$	—	$	—
Interest cost	22,622			21,106			3,473			3,085			616		540
Expected return on plan assets	(28,533		)	(31,447		)	(4,229		)	(3,782		)	—		—
Amortization of net (gain) loss	9,765			11,130			1,669			3,182			157		174
Amortization of prior service cost	(724		)	57			(1,008		)	(1,008		)	—		—
Net periodic benefit cost	$	3,130		$	846		$	41		$	1,672		$	773	$	714

PNM does not anticipate making any contributions to its pension trust in 2014 due to the current funded status of the pension plan.  PNM made contributions to its pension plan trust of zero and $60.0 million in the three and nine months ended September 30, 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the PNM pension plan trust for 2015-2018 are estimated to total $50.0 million. These anticipated contributions were developed using current funding assumptions, with discount rates of 4.5% to 5.3%. Actual amounts required to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made contributions to the OPEB trust of $0.8 million and $2.4 million in the three and nine months ended September 30, 2014 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2013. PNM expects to make contributions to the OPEB trust totaling $3.3 million in 2014 and $14.0 million for 2015-2018.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.2 million in the three and nine months ended September 30, 2014 and $0.4 million and $1.1 million in the three and nine months ended September 30, 2013 and are expected to total $1.6 million during 2014.

47

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

TNMP Plans

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

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	59		$	75		$	—	$	—
Interest cost	798			772			155			141			10		9
Expected return on plan assets	(1,132		)	(1,212		)	(133		)	(126		)	—		—
Amortization of net (gain) loss	166			262			(31		)	—			—		—
Amortization of prior service cost	—			—			8			14			—		—
Net Periodic Benefit Cost (Income)	$	(168	)	$	(178	)	$	58		$	104		$	10	$	9
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	178		$	225		$	—	$	—
Interest cost	2,395			2,315			464			424			29		27
Expected return on plan assets	(3,395		)	(3,637		)	(400		)	(377		)	—		—
Amortization of net (gain) loss	499			787			(92		)	—			—		—
Amortization of prior service cost	—			—			24			43			—		—
Net Periodic Benefit Cost (Income)	$	(501	)	$	(535	)	$	174		$	315		$	29	$	27

TNMP does not anticipate making additional contributions to its pension trust in 2014 due to the current funded status of the pension plan. TNMP made contributions to its pension plan trust of zero and $1.0 million in the three and nine months ended September 30, 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, TNMP estimates there would be no contributions to its pension plan trust for 2015-2018. The anticipated contributions were developed using current funding assumptions, including discount rates of 4.5% and 5.3%. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions to the OPEB trust of zero and $0.3 million in the three and nine months ended September 30, 2014 and zero and $0.3 million in the three and nine months ended September 30, 2013. TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2014 and $1.4 million for 2015-2018. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three and nine months ended September 30, 2014 and 2013 and are expected to total $0.1 million during 2014.

48

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(11) Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company occasionally enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 12) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.

With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Commitments and Contingencies Related to the Environment

Nuclear Spent Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. In 2010, the court ordered an award to the PVNGS owners for their damages claim for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, and on October 7, 2014, APS received a settlement payment of $57.4 million for costs paid through June 30, 2011, for DOE’s failure to accept spent nuclear fuel generated at PVNGS. PNM’s share of the settlement is $5.9 million, which was recorded in other deferred credits. The settlement agreement also establishes a process for the payment of subsequent claims through December 30, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. The first claim is due no later than October 31, 2014, for costs paid between July 1, 2011, and June 30, 2014. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At September 30, 2014 and December 31, 2013, PNM had a liability for interim storage costs of $12.2 million and $11.9 million included in other deferred credits.

49

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high-level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision. The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which requires either an EIS or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action. In September 2012, the NRC issued a directive to its staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision within 24 months. In September 2013, the NRC issued its draft EIS to support an updated Waste Confidence Decision. In late 2013, the NRC held a series of nationwide public meetings to receive stakeholder input on the draft EIS. In September 2014, the NRC issued its final rule codifying the results of analyses from a generic EIS regarding the continued storage of spent nuclear fuel.  The rule became effective on October 20, 2014. Untimely resolution by the NRC of the remand from the D.C. Circuit could have an adverse impact on certain NRC licensing actions. Currently, PVNGS does not have any licensing actions pending with the NRC. The petitioners also sought a writ requiring the NRC to comply with the law and resume processing DOE’s pending license application for a nuclear waste site at Yucca Mountain in Nevada. In August 2013, the D.C. Circuit ordered the NRC to resume reviewing the license application. PNM is unable to predict the impact of these decisions.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of the intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of the intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. On May 16, 2014, the DOE adjusted the fee to zero. In 2013, the one-mill fee for PNM’s share of the output from all three units at PVNGS amounted to $3.0 million. The fee applicable to PVNGS Units 1 and 2 is recovered by PNM in its retail rates. PNM anticipates challenges to this action and is unable to predict its ultimate outcome.

The Clean Air Act

Regional Haze

In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.

SJGS

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

50

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

technology (“SCR”) on all four units by September 21, 2016. In November 2012, EPA approved all components of the SIP, except for the NOx BART determination for SJGS, which continued to be subject to the FIP.

PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA’s decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule. These parties also formally asked EPA to stay the effective date of the rule. Several environmental groups intervened in support of EPA. The parties file periodic status reports with the Tenth Circuit, but proceedings are being held in abeyance as agreed to by the parties.

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

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

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013, reflecting the terms of the non-binding agreement. NMED developed a RSIP and submitted it to the EIB for approval in May 2013. The EIB approved the RSIP in September 2013 and it was submitted to EPA for approval on October 18, 2013. EPA published its proposed approval of the RSIP in the Federal Register on May 12, 2014. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and will become effective on November 10, 2014. The deadline for filing petitions for review is December 8, 2014.

Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM took steps to commence installation of SCRs at SJGS. In October 2012, PNM entered into a contract 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 December 31, 2014. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million. The costs for the project to install SCRs would encompass installation of technology to comply with the NAAQS requirements described below.

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

The above estimates include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM’s share under either SCRs or SNCRs as described above would be about 46.3%.

Following the February 2013 development of the alternative BART compliance plan, PNM began taking steps to prepare for the potential installation of SNCRs on Units 1 and 4 due to the long lead times on certain equipment purchases. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider. In July 2014, PNM entered into a contract for management of the SNCR construction and in September 2014 entered into a construction and procurement contract.

NMPRC Filing – On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. In this filing, PNM requested:

• Permission to retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date along with a regulated return on those costs

51

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

• A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018

• An order allowing cost recovery for PNM’s share of the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million

• A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM; the net impact of this exchange and the retirement of Units 2 and 3 would be a reduction of 340 MW in PNM’s ownership of SJGS

The December 20, 2013 NMPRC filing identified a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM has included the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. A proposed stipulated settlement, which is pending approval before the NMPRC, would provide that the additional solar capacity be recovered in base rates rather than through the renewable energy rider. See Note 12. Specific approvals to acquire the gas facility and the treatment of associated costs will be made in future filings. PNM estimates the cost of these identified resources would be approximately $268.3 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs would be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of SNCRs. See Note 12 for additional information concerning PNM’s filing for NMPRC approvals regarding these matters.

As discussed under SJGS Ownership Restructuring Matters below, the owners of SJGS are attempting to negotiate agreements concerning numerous matters, the resolution of which is necessary in order to facilitate the shutdown of SJGS Units 2 and 3 and comply with the RSIP. PNM’s requests in the December 20, 2013 NMPRC filing were based on the status of the negotiations among the SJGS owners at that time. In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements are memorialized in the resolution and term sheet described below.

On October 1, 2014, PNM, the staff of the NMPRC, the NMAG, New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico filed a stipulation with the NMPRC. NMIEC subsequently joined the agreement. Statements of opposition were filed by New Energy Economy, Southwest Generation, the City of Santa Fe, Santa Fe County, and the Coalition for Clean, Affordable Energy.

Under the terms of the stipulation, PNM:

• Would be authorized to abandon SJGS Units 2 and 3 effective December 31, 2017

• Would be granted a CCN for an additional 132 MW of SJGS Unit 4 capacity as of January 1, 2018 with a rate base value of $26 million plus any reasonable and prudent investments made in Unit 4 prior to that date; PNM would reduce its carrying value of SJGS Unit 3 by this $26 million

• Would recover 50% of the estimated $231 million undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a twenty year period and would include a return on the unrecovered amount at PNM’s WACC; at September 30, 2014, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $284 million

• Would be granted a CCN for 134 MW of PVNGS Unit 3 at a January 1, 2018 value of $221.1 million ($1,650 per KW); PNM’s ownership share of PVNGS would also be subject to a capacity factor performance threshold of 75% for a seven year period beginning January 1, 2018; subject to certain exceptions, if the capacity factor is not achieved in any year, PNM would refund the cost of replacement power through its FPPAC; at September 30, 2014, PNM’s net book value of PVNGS Unit 3 was approximately $143 million

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

• Would recover its reasonable and prudent costs of installation of the SNCRs and equipment to comply with NAAQS requirements at SJGS Units 1 and 4 up to $90.6 million

• Would not be allowed to recover a total of approximately $20 million of increased operations and maintenance costs associated with the agreement reached with the remaining SJGS participants, additional fuel handling expenses, and certain other costs incurred in efforts to comply with the CAA

The public hearing in the NMPRC case is scheduled to begin on January 5, 2015. PNM expects a decision from the NMPRC in the first quarter of 2015. PNM is unable to predict if the NMPRC will approve the stipulation. If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. Although PNM would record the regulatory disallowance upon approval by the NMPRC, the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order, as well as PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3 and PVNGS Unit 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values of the plants. Based on the provisions of the stipulation as filed and PNM’s current projection of December 31, 2017 book values, PNM estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.

SJGS Ownership Restructuring Matters – As discussed in the 2013 Annual Report on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The SJPPA that governs the operation of SJGS expires on July 1, 2022 and the contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. The California participants have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4.

The SJGS participants have engaged in negotiations concerning the implementation of the RSIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 that could have resulted in PNM acquiring additional ownership in Unit 4 prior to the shutdown of SJGS Units 2 and 3. The discussions among the SJGS participants regarding restructuring have also included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs.

On June 26, 2014, a non-binding resolution was unanimously approved by the SJGS Coordination Committee (the “Resolution”). The Resolution identifies the participants who would be exiting active participation in SJGS effective December 31, 2017, and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCRs, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating approximately 59%. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants will need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, the remaining participants are in the process of negotiating agreements concerning future fuel supply for SJGS, the resolution of which is necessary for continued operation of SJGS after December 31, 2017. On September 2, 2014, the SJGS Coordination Committee adopted a non-binding amendment to the Resolution, which provides for allocation of future costs of decommissioning among current SJGS owners using a time-based sliding scale and outlines indemnification obligations.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the Resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. PNM filed the Fuel and Capital Funding Agreement with FERC on September 18, 2014, with a request for a retroactive effective date to July 1, 2014. FERC has 60 days from the date of filing to accept the filing. The Fuel and Capital Funding Agreement provides that the SJGS participants will return to the status quo if required regulatory approvals are not obtained or a binding restructuring agreement is not reached.

The participants continue to negotiate other definitive agreements that would formalize the matters contained in the Resolution, as amended. A number of regulatory approvals are required to implement the proposed ownership restructuring of SJGS. Any final binding agreements relating to the ownership restructuring are subject to the approval of each participant’s board or other decision-making body and are subject to required regulatory approvals. PNM is unable to predict the outcome of the negotiations, whether definitive agreements will be reached among the owners, or whether required approvals will be obtained.

Other Developments and Current Status – The SJPPA requires PNM, as operating agent, to obtain approval of capital improvement project expenditures from participants who have an ownership interest in the relevant unit or property common to more than one unit. As provided in the SJPPA, specified percentages of both the outstanding participant shares, based on MW ownership, and the number of participants in the unit or common property must be obtained in order for a capital improvement project to be approved. PNM presented the SNCR project, including NAAQS compliance requirements described below, to the SJGS participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. In addition, other capital projects related to Unit 4 were not approved by the participants. PNM subsequently requested that the owners of Unit 4 approve the expenditure of costs critical to being able to comply with the time frame in the RSIP with respect to the Unit 4 project of $1.9 million on March 10, 2014 and $6.4 million on June 27, 2014. The Unit 4 owners did not approve either of the requests.

PNM, in its capacity as operating agent of SJGS, is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM must evaluate its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and take reasonable and prudent actions as it deems necessary. Therefore, on March 10, 2014 and July 14, 2014, PNM, as operating agent for SJGS, issued “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.

As discussed above, EPA approved the RSIP and withdrew the FIP on October 9, 2014 and those approvals will become effective on November 10, 2014. PNM believes significant progress is being made towards implementation of the RSIP. However, the final implementation of the RSIP is still dependent upon PNM obtaining NMPRC approval to retire San Juan Units 2 and 3 and a final binding agreement among the SJGS owners on a revised ownership structure to facilitate the retirement of these two units. PNM can provide no assurance that these requirements will be accomplished. If the RSIP requirements ultimately are not implemented due to adverse or alternative regulatory, legislative, legal, or restructuring developments or other factors, PNM would need to pursue other alternatives to address compliance with the CAA.PNM will seek recovery from its ratepayers for costs that may be incurred as a result of the CAA requirements. PNM is unable to predict the ultimate outcome of these matters.

Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance its share of the installation. It is possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation or legislation, if any, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Four Corners

On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to close permanently Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were shutdown by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.

APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041.  The Navajo Nation approved these amendments in March 2011.  The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant, which the Four Corners participants are pursuing.  A federal environmental review is underway as part of the DOI review process.  In March 2014, APS received a draft of the EIS in connection with the DOI review process.  On June 19, 2014, PNM submitted comments on the draft EIS as owner and operator of two electric transmission lines that are part of the connected action for the EIS.  In addition, APS will require a PSD permit from EPA to install SCR control technology at Four Corners.  PNM cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners participants.

The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of possible future climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

PNM is continuing to evaluate the impacts of EPA’s BART determination for Four Corners. PNM estimates its share of costs, including PNM’s AFUDC, to be up to $80.3 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM is unable to predict the ultimate outcome of this matter.

Four Corners BART FIP Challenge

On October 22, 2012, WEG filed a petition for review in the Ninth Circuit challenging the Four Corners BART FIP.  In its petition, WEG alleges that the final BART rule results in more air pollution being emitted into the air than allowed by law and that EPA failed to follow the requirements of the ESA.  APS intervened in this matter and filed a motion to dismiss this lawsuit for lack of jurisdiction or alternatively to transfer the lawsuit to the Tenth Circuit. On February 25, 2013, the Ninth Circuit denied APS’ motion to dismiss, but granted the request to transfer the case to the Tenth Circuit. Oral argument was presented before the Tenth Circuit on January 23, 2014. On July 23, 2014, the Tenth Circuit issued a unanimous decision affirming EPA’s action and denying WEG’s petition for review. On September 15, 2014, the Tenth Circuit issued its mandate marking an official end to the case.

Regional Haze Challenges

On December 27, 2012, WEG filed a petition for review in the Tenth Circuit challenging the SO₂ and particulate matter emissions elements of EPA’s approval of New Mexico’s Regional Haze SIP.  On February 26, 2013, HEAL Utah and other environmental groups filed petitions in the Tenth Circuit challenging EPA’s final approval of the remaining elements of New Mexico’s Regional Haze SIP, as well as EPA’s approval of the Albuquerque/Bernalillo County Air Quality Control Board SIP. PNM was granted intervention in both matters and the Tenth Circuit consolidated the two matters based on the similarity of issues. Oral argument was heard before the Tenth Circuit on March 20, 2014. On October 21, 2014, the Tenth Circuit denied the petitions for review and affirmed EPA’s actions. PNM is unable to predict whether petitions for rehearing or appeals of the decision will be filed.

55

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO₂,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO₂ and the 24-hour SO₂ standard. New Mexico is in attainment for the 1-hour NOx NAAQS. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO₂ NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO₂ sources to identify maximum 1-hour SO₂ concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO₂ sources through ambient monitoring or modeling. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO₂ NAAQS.  Although the determination process has not been finalized, PNM believes that compliance with the 1-hour SO₂ standard may require operational changes and/or equipment modifications at SJGS. On November 8, 2013, PNM received an amendment to its air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. In the revised permit, PNM agreed to reduce SO₂ emissions to 0.1 pound per MMBTU on SJGS Units 1 and 4 and to install equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO₂, and particulate matter. These reductions will help SJGS meet the NAAQS. It is anticipated that the equipment modifications would be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities at SJGS. The cost of this technology is dependent upon the type of control technology that is ultimately determined to be NOx BART at SJGS. See Regional Haze – SJGS above.

EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications discussed above will assist the plant in complying with the particulate matter NAAQS.

In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 0.060-0.070 parts per million. EPA is reviewing its 2008 standard and has completed certain assessment phases of developing a new ozone standard. EPA is under a court order to issue a draft proposal by December 1, 2014 and finalize the new standard by October 1, 2015.  Depending upon where the standard for ozone is set, San Juan County, where SJGS is situated, could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. As a result, SJGS could be required to install further NOx controls to meet a new ozone NAAQS. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional NOx controls would be required at any of its affected facilities as a result of ozone non-attainment designation.

Citizen Suit Under the Clean Air Act

The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS’s emissions performance. In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM’s mercury controls. NMED and plaintiffs sought to require PNM to implement additional mercury controls. PNM estimates the implementation would increase annual mercury control costs for the entire station, which are currently $0.7 million, to a total of $6.6 million. On March 23, 2014, the court entered a stipulated order reflecting an agreement reached by the parties. Under the stipulated order, PNM is required to repeat the mercury study required under the Consent Decree using sorbent traps instead of the monitoring system used in the initial study. PNM has completed stack testing and anticipates finalizing the study report by the end of 2014. The results of the mercury study will establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM cannot predict the ultimate outcome of this matter.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Section 114 Request

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

Four Corners Clean Air Act Lawsuit

In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, the Four Corners participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, the Four Corners owners may reinstate their motions to dismiss without risk of default. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

WEG v. OSM NEPA Lawsuit

In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012.  In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM.  Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine.  WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008.  WEG alleges various National Environmental Policy Act (“NEPA”) violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents.  WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and SJGS. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. Although an agreement was reached resolving claims related to the CAA, the agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.

Cooling Water Intake Structures

EPA issued its final cooling water intake structures rule on May 19, 2014, which establishes national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens)

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The final rule was published on August 15, 2014 and became effective October 14, 2014.

The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting “best technology available” standards for reducing impingement. To minimize entrainment mortality, the permitting authority must establish the “best technology available” for entrainment on a site-specific basis, taking into consideration an array of factors, including social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority. PNM is performing analyses to determine the potential costs of compliance with the rule. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. APS is currently in discussions with EPA Region 9, the National Pollutant Discharge Elimination System permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS has indicated that it does not expect such costs to be material.

Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants.  EPA’s proposal offers numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning waste operations.  The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits. Depending on which alternative EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. PNM has reviewed the proposed rule and continues to assess the potential impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. On April 9, 2014, several environmental groups agreed to allow EPA until September 30, 2015 to issue final effluent limits. Under the agreement, EPA will not seek any further extensions and will follow through on a separate agreement to issue a final rule on coal ash waste disposal by December 19, 2014. If EPA misses the December 19, 2014 deadline to issue a coal ash rule, then the agreement allows the environmental groups to require the EPA to issue the final effluent limits earlier. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. 

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of the former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM’s obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

similar results. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property.   This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels,  and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. It is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels.  Additional testing and analysis will need to be performed before conclusions can be reached regarding the cause of the increased nitrate levels or the method and cost of remediation.  PNM is unable to predict the outcome of these matters.

Coal Combustion Byproducts Waste Disposal

CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production.  Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office. 

In June 2010, EPA published a proposed rule that includes two options for waste designation of coal ash. One option is to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA’s proposal does not address the placement of CCBs in surface mine pits for reclamation. An OSM CCB rulemaking team has been formed to develop a proposed rule governing the placement of CCBs at coal mining and reclamation operations. 

On April 5, 2012, several environmental groups, including Sierra Club, filed a citizen suit in the D.C. Circuit claiming that EPA has failed to review and revise RCRA’s regulations with respect to CCBs. The groups allege that EPA has already determined that revisions to the CCBs regulations are necessary and that EPA now has a non-discretionary duty to revise the regulations. The environmental groups asked the court to direct EPA to complete its review of the regulation of CCBs and a hazardous waste analytical procedure and to issue necessary revisions of such regulations as soon as possible. Two industry group members subsequently filed separate lawsuits in the D.C. Circuit seeking to ensure that disposal of coal ash would not be regulated as a hazardous waste. The environmental and industry lawsuits have been consolidated. On January 29, 2014, EPA entered into a consent decree directing EPA to publish its final action regarding whether or not to pursue the proposed non-hazardous waste option for CCBs by December 19, 2014.

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

Hazardous Air Pollutants (“HAPs”) Rulemaking

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

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Other Commitments and Contingencies

Coal Supply

The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At September 30, 2014 and December 31, 2013, prepayments for coal, which are included in other current assets, amounted to $26.1 million and $12.3 million. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement to supply processed coal for operation of SJGS through 2017. Under the coal sales agreement, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.

PNM and the other owners of SJGS are evaluating alternatives for the supply of coal after the expiration of the current coal sales agreement. As discussed under SJGS Ownership Restructuring Matters above, the Resolution and the non-binding term sheet approved by the SJGS Coordination Committee on June 26, 2014 recognize that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants will need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017. The remaining participants are in the process of negotiating agreements concerning future fuel supply for SJGS with SJCC and BHP. On October 1, 2014, the San Juan Fuels Committee approved a resolution authorizing an amendment to the coal sales agreement. The parties to the coal sales agreement and the amendment are SJCC, PNM, and Tucson. The amendment provides for the negotiation of a potential purchase transaction for the mine assets by one or more of the utilities, an affiliate, or another entity agreed to by the parties to be consummated on or before December 31, 2016. PNM anticipates that a consummated arrangement would ultimately involve a third-party mining company either as the owner of the mine or as a contract miner and could involve some or all of the remaining participants in SJGS. The amendment, which was effective as of October 2, 2014, also releases the parties from the obligation to negotiate an extension of the coal sales agreement, but does not impact the utilities’ option to purchase the mining assets at the end of the current contract term if the purchase transaction is not completed. On October 2, 2014, the parties also entered into an agreement that provides the SJGS participants with access to data necessary to evaluate the mine assets and liabilities. PNM cannot currently predict the outcome of these negotiations or if a transaction will be consummated.

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, expiring in 2031, was entered into with that entity. The BHP subsidiary is to be retained as the mine manager and operator until December 2016. Coal costs are anticipated to increase approximately 21% for the first full year of the new contract and will further increase over the contract term. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

In 2013, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. This estimate reflects that, with the proposed shutdown of SJGS Units 2 and 3 described above, the mine providing coal to SJGS will continue to operate through 2053, the anticipated life of SJGS. The 2013 estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new coal supply agreement. Based on the 2013 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $53.9 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of June 30, 2014. At September 30, 2014 and December 31, 2013, liabilities, in current dollars, of $22.9 million and $23.8 million for surface mine reclamation and $8.4 million and $7.8 million for underground mine reclamation were recorded in other deferred credits.

PNM collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from ratepayers for final reclamation of the surface mines at $100.0 million. Previously, PNM recorded a regulatory asset for the $100.0 million and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA discussed under The Clean Air Act – Regional Haze – SJGS above, an updated coal mine reclamation study was requested by the SJGS participants. As discussed under Coal

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant. The updated coal mine reclamation study indicates reclamation costs have increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, although the timing of payments will be delayed. The shutdown of Units 2 and 3 would reduce the amount of CCBs generated over the remaining life of SJGS, which could result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. How costs would be divided among the owners of SJGS has not been finalized. Regulatory determinations made by the NMPRC may also affect the impact on PNM. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

San Juan Underground Mine Fire Incident

On September 9, 2011, a fire was discovered at the underground mine owned and operated by SJCC that provides coal for SJGS. The federal Mine Safety and Health Administration (“MSHA”) was notified of the incident. On September 12, 2011, SJCC informed PNM that the fire was extinguished. However, MSHA required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. SJCC regained entry into the sealed area of the mine in early March 2012. At that time, MSHA conducted a root cause analysis inspection of the incident area, but has not yet issued its report. SJCC completed inspection of the mine equipment and reported no significant damage. SJCC removed the equipment from the impacted mine panel and reassembled it at a new panel face. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. Coal inventories have been restored to pre-incident levels and SJCC provided notice to PNM on September 23, 2014 that the mine has been restored to normal operations.

The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM included the portion of such costs allocable to its customers subject to New Mexico regulation in its FPPAC. PNM’s filings with the NMPRC reflected an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by between $17.4 million and $21.6 million. SJCC submitted an insurance claim regarding the costs it incurred due to the mine fire and informed PNM that it settled with its insurance carrier. PNM’s portion of the insurance recovery is $18.7 million. PNM has credited its FPPAC balancing account for the insurance proceeds allocable to PNM’s New Mexico jurisdictional customers. See Note 12.

Continuous Highwall Mining Royalty Rate

In August 2013, the DOI Bureau of Land Management (“BLM”) issued a proposed rulemaking that would retroactively apply the surface mining royalty rate of 12.5% to continuous highwall mining (“CHM”).  Comments regarding the rulemaking were due on October 11, 2013, and PNM submitted comments in opposition to the proposed rule. There is no legal deadline for adoption of the final rule.

SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS.  In March 2001, SJCC learned that the DOI Minerals Management Service (“MMS”) disagreed with the application of the underground royalty rate to CHM.  In August 2006, SJCC and MMS entered into a settlement agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal.  The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed.  PNM’s share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM’s FPPAC. PNM is unable to predict the outcome of this matter.

SJCC Arbitration

The coal supply agreement for SJGS provides that the participants in SJGS have the right to audit the costs billed by SJCC. An independent accounting firm has been engaged to perform audits of the costs billed under the provisions of the contract. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC. As provided in the contract, certain issues were submitted to a panel for binding arbitration. The issues were: 1) whether the SJGS participants owed SJCC unbilled mining costs of $5.2 million or whether SJCC owed the SJGS participants overbilled mining costs of $1.1 million, and 2) whether SJCC billed the SJGS participants $13.9 million as mining costs that SJCC should have considered to be

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

capital costs, which were not billable under the mining contract.  PNM’s share of amounts subject to the arbitration are approximately 46.3%. A hearing before the arbitration panel on the remaining issues was held in May 2014. The arbitration panel found in favor of SJCC on both issues.  Of PNM’s share of the costs, approximately 33% of the first issue was passed through PNM’s FPPAC and the rest impacted earnings in the three months ended June 30, 2014. The amounts related to the second issue were recorded when billed in prior periods and had no impact in 2014.

Four Corners Severance Tax Assessment

On May 23, 2013, the New Mexico Taxation and Revenue Department (“NMTRD”) issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners. PNM’s share of any amounts paid related to this assessment would be approximately 8%, all of which would be passed through PNM’s FPPAC. For procedural reasons, on behalf of the Four Corners co-owners, including PNM, the coal supplier made a partial payment of the assessment and immediately filed a refund claim with respect to that partial payment in August 2013. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. PNM believes the assessment and the refund claim denial are without merit, but cannot predict the outcome of this matter.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.6 billion per occurrence. Commercial insurance carriers provide $375 million and $13.2 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential retrospective premium assessment per incident for all three units is $38.9 million, with a maximum annual payment limitation of $5.7 million.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). Effective April 1, 2014, a sublimit of $2.25 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium assessments of $4.8 million for each retrospective premium assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions.

Water Supply

Because of New Mexico’s arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Rio Bravo, Afton, Luna, and Lordsburg. Water availability is not an issue for these plants at this time. However, prolonged drought, ESA activities, and a Federal lawsuit by the State of Texas (suing the State of New Mexico over water allocations) could pose a threat of reduced water availability for these plants.

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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for forty years.

PVNGS Water Supply Litigation

In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows.

San Juan River Adjudication

In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo Nation’s water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees.  The court issued an order in August 2013 finding that no evidentiary hearing was warranted in the Navajo Nation proceeding, and on November 1, 2013 issued a Partial Final Judgment and Decree of the Water Rights of the Navajo Nation approving the proposed settlement with the Navajo Nation. Several parties filed a joint motion for a new trial, which was denied by the court. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM has entered its appearance in the appellate case. No hearing dates or deadlines have been set at this time.

PNM is participating in this proceeding since PNM’s water rights in the San Juan Basin may be affected by the rights recognized in the settlement agreement as being owned by the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin. PNM is unable to predict the ultimate outcome of this matter or estimate the amount or range of potential loss and cannot determine the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. Final resolution of the case cannot be expected for several years. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

Rights-of-Way Matter

On January 28, 2014, the County Commission of Bernalillo County, New Mexico passed an ordinance requiring utilities to enter into a use agreement and pay a yet to be determined fee as a condition to installing, maintaining, and operating facilities on county rights-of-way. The fee is purported to compensate the county for costs of administering, maintaining, and capital improvements to the rights-of-way. On February 27, 2014, PNM and other utilities filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. In June 2014, the utilities and Bernalillo County reached an agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement.  The federal court ruled in favor of Bernalillo County, dismissing the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. If the challenges to the ordinance are unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS’ fuel cost adjustment clause

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

Navajo Nation Allottee Matters

A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both.  In March 2010, the court ordered that the entirety of the plaintiffs’ case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court.  In May 2010, plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (“BIA”), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director’s decision to the DOI, Office of Hearings and Appeals, Interior Board of Indian Appeals. Following briefing on the merits, on August 20, 2013, that board issued a decision upholding the Regional Director’s decision that the allottees had failed to perfect their appeals, and dismissed the allottees’ appeals, without prejudice.  The allottees have not refiled their appeals. Although this matter was dismissed without prejudice, PNM considers the matter concluded. However, PNM continues to monitor this matter in order to preserve its interests regarding any PNM-acquired rights-of-way.

In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice.  On April 2, 2014, the allotees’ appeal was dismissed with prejudice concluding this matter. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments.  PNM is in the process of investigating the validity of this notice of revocation and its potential impact in light of the BIA’s position and the recent dismissal with prejudice of the appeal, and is therefore unable at this time to predict the likely outcome of this matter.

(12) Regulatory and Rate Matters

The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

PNM

Renewable Portfolio Standard

The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements are 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015,

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

subject to the limitation of the RCT. In December 2013, the NMPRC modified the RCT calculation to establish a two to one REC weighting for renewable energy from the non-wind/non-solar category, such as geothermal resources. On motions for rehearing, the NMPRC reversed its weighting decision in April 2014.

The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges.

The NMPRC approved PNM’s 2014 renewable energy procurement plan on December 18, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements include 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW, beginning January 1, 2015 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015.

PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements include the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $79.3 million. The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11). On September 25, 2014, a stipulated settlement was filed by PNM, staff of the NMPRC, the NMAG, NMIEC, Coalition for Clean Affordable Energy, and Western Resource Advocates. The stipulation would approve PNM’s procurement proposals; however, the costs for the 40 MW of solar would be included in base rates to be set in PNM’s next general rate case rather than through PNM’s renewable energy rider. Under the agreement, PNM will be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT. The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans. A public hearing on the stipulation was held on October 27, 2014. At the conclusion of the hearing, the Hearing Examiner asked the parties to provide her with a draft Certification of Stipulation by November 7, 2014.  PNM expects a decision by December 2, 2014.

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

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The rider will terminate upon a final order in PNM’s next general rate case unless the NMPRC authorizes PNM to continue it. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM would be required to refund the amount over 10.5% to customers during May through December of the following year. On April 1, 2014, PNM made a filing with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013. At the currently approved rider rate, PNM would collect an estimated $34.6 million annually. In its 2015 renewable energy procurement plan, PNM has proposed to increase the rate to collect $44.7 million in 2015 through its renewable energy rider.

Energy Efficiency and Load Management

Program Costs

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In October 2012, PNM filed an energy efficiency program application for programs proposed to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive. The NMPRC approved PNM’s program application, including the annual profit incentive discussed below, on November 6, 2013.

On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. The NMPRC has not yet acted upon PNM’s application.

Disincentives/Incentives

The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. In 2010, PNM began implementing a NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. In November 2013, the NMPRC issued an order authorizing PNM to recover an incentive equal to 7.6% of annual program costs beginning with program implementation in December 2013. Based on PNM’s currently approved program costs, this equates to an estimated annual incentive of $1.7 million.

In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million. PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. The NMPRC has not yet acted upon PNM’s application.

Energy Efficiency Rulemaking

On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. Included in the proposed rule is a provision that would limit incentive awards to an amount equal to the utility’s WACC times its approved annual program costs. The NMPRC received comments and a public hearing was held on November 20, 2013. The NMPRC issued an order on October 8, 2014 adopting the proposed rule.

FPPAC Continuation Application

Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On May 28, 2013, PNM filed the required continuation application and requested that its current FPPAC be modified to increase the reset frequency of the fuel factor from annually to quarterly, to allow PNM to retain 10% of its off-system sales margin, and to apply the same carrying charge rate to both over and under collections in the balancing account. On December 20, 2013, a stipulated agreement was filed to resolve this case. On April 23, 2014, the NMPRC approved the stipulation. The settlement allows PNM to retain 10% of off-system sales margin from July 1, 2013 through December 31, 2016, resolves all costs related to the San Juan Coal mine fire discussed in Note 11, resolves the ratemaking treatment for coal pre-treatment at SJGS until the next rate case, requires PNM to write-off $10.5 million of the under-collected balance in its FPPAC balancing account, and requires PNM to extend the recovery of the remaining under-collected balance over 18 months beginning July 1, 2014. PNM recorded the $10.5 million write off as a regulatory disallowance in the fourth quarter of 2013.

Integrated Resource Plan

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3.

Applications for Approvals to Purchase Rio Bravo

As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Report on Form 10-K, PNM entered into an agreement to purchase Rio Bravo, formerly known as Delta, a 132 MW natural gas peaking unit from which PNM acquired energy and capacity under a PPA. The agreement to purchase Delta required approvals by the NMPRC and FERC. On June 26, 2013, the NMPRC granted PNM’s CCN application and approved PNM’s proposed ratemaking treatment. FERC approved the purchase on February 26, 2013. PNM closed on the purchase on July 17, 2014.

Application for Approval of La Luz Generating Station

On May 17, 2013, PNM filed an application with the NMPRC for a CCN to construct, own, and operate a 40 MW gas-fired generating facility near Belen, New Mexico. The application also requested a determination of related ratemaking principles and treatment. PNM has entered into a contract for purchase of the turbine to be used for this project and a separate contract for the construction of the facility on a turn-key basis. On February 20, 2014, a stipulated agreement was filed that would resolve the case. The parties to the stipulation are PNM, the NMPRC staff, and another intervenor. The parties to the stipulation agree that a CCN should be granted and establishes a value of up to $56.0 million to be included in rate base for the facility. A public hearing was held on April 29, 2014. The NMPRC issued an order certifying the stipulation on June 18, 2014. Construction of the facility is expected to be completed in late 2015.

San Juan Generating Station Units 2 and 3 Retirement

On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation is set forth in Note 11.

The public hearing in the NMPRC case is scheduled to begin on January 5, 2015. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM is unable to predict the outcome of these matters.

Formula Transmission Rate Case

On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. In a settlement of a prior transmission rate case, the parties agreed that no party would oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM’s proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula.

On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC’s order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC on January 2, 2013. The new rates apply to all of PNM’s wholesale electric transmission service customers. The new rates do not apply to PNM’s retail customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding.

City of Gallup, New Mexico Contract

PNM provided both energy and power services to Gallup, PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On May 1, 2013, PNM requested FERC approval of the amended agreement to be effective July 1, 2013. On June 21, 2013, FERC approved the amended agreement.

On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility.  PNM’s contract with Gallup ended on June 29, 2014.  PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014 and totaled $11.7 million during 2013.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.3 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5-year period.

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

On February 21, 2013, the PUCT filed a proposed rule to permit customers to opt-out of the AMS deployment. The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service will be borne by opt-out customers through an initial fee and ongoing monthly charge. All transmission and distribution utilities in ERCOT were required to initiate proceedings to establish these charges.

On September 30, 2013, TNMP filed an application to set the initial fee and monthly charges to be assessed for non-standard metering service provided to those retail customers who choose to decline the advanced meter necessary for standard metering service. TNMP’s filing sought recovery of $0.2 million through proposed initial fees ranging from $142.84 to $247.48 and an additional $0.5 million in annual ongoing expenses via a proposed monthly charge of $38.99. On June 20, 2014, the PUCT approved a settlement among the parties permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of October 11, 2014, the end of the initial period in which a customer could elect non-standard metering, 59 customers have made

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor that includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On August 28, 2012, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.2 million effective January 1, 2013. On October 25, 2013, the PUCT approved a settlement that permits TNMP to collect an aggregate of $5.6 million beginning March 1, 2014. On May 30, 2014, TNMP filed its 2015 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.7 million to be collected beginning March 1, 2015. The request included an incentive bonus of $1.5 million for having achieved demand savings for the 2013 program year that exceeded the goal. On August 6, 2014, the parties filed a stipulation resolving TNMP’s application. The PUCT approved the settlement on September 11, 2014, permitting TNMP to collect $5.7 million beginning March 1, 2015. TNMP recorded the $1.5 million incentive bonus for 2013 in the three months ended September 30, 2014.

Transmission Cost of Service Rates

TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities.

On January 31, 2013, TNMP filed an application to update its transmission rates to reflect an increase in total rate base of $21.9 million, which would increase revenues $2.9 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on March 20, 2013.

On August 1, 2013, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $18.1 million, which would increase revenues by $2.8 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on September 17, 2013.

On January 21, 2014, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $18.2 million, which would increase revenues by $2.9 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on March 13, 2014.

On July 18, 2014, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $25.2 million, which would increase revenues by $4.2 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on September 8, 2014.

(13) Income Taxes

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

On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction will be phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment, which was in three months ended June 30, 2013. At that time, the portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The increase in the regulatory liability was $23.9 million. In addition, the portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax expense of $1.2 million during the three months ended June 30, 2013. Changes in the estimated timing of

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2014, PNM’s regulatory liability was reduced by $4.6 million, which increased deferred tax liabilities. Additionally, deferred tax assets not related to PNM’s regulatory activities were reduced by $0.2 million, which increased income tax expense in the Corporate and Other segment.

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

In 2013, the FASB issued Accounting Standards Update 2013-11, which requires entities to present liabilities for uncertain tax positions as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such carryforward could be used to offset those liabilities upon settlement.  The update was required to be applied prospectively for periods beginning after December 15, 2013, and early adoption was permitted.  The Company elected not to adopt the change for 2013, but did adopt it for 2014 as required by the update.  Had the Company applied the update at December 31, 2013, the effect would have been decreases in net operating loss deferred tax assets of $19.9 million for PNMR, $11.2 million for PNM, and $6.8 million for TNMP, along with the elimination of the corresponding assets and liabilities associated with uncertain tax positions. There was no impact to earning from adopting the update.

In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008 resulting in years prior to 2009 being closed to examination by federal taxing authorities. As a result of the settlement, the Company received net federal tax refunds of $2.0 million. The IRS examination resulted in the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. The settlement of the IRS examination, including the uncertain tax position matters, resulted in PNMR recording an income tax benefit of $0.2 million on a consolidated basis in the three months ended June 30, 2014. PNM recorded an income tax expense of $1.1 million, TNMP reflected no impact, and an income tax benefit of $1.3 million was recorded in PNMR’s Corporate and Other segment. After the settlements, the liabilities related to uncertain tax positions for PNMR, PNM, and TNMP were $14.3 million, $11.5 million, and none.

(14) Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(In thousands)
Services billings:
PNMR to PNM	$	20,813	$	22,241	$	64,069	$	65,729
PNMR to TNMP	6,471		6,731		20,695		20,948
PNM to TNMP	142		140		402		381
TNMP to PNMR	20		2		21		6
Interest billings:
PNMR to TNMP	65		139		245		354
PNMR to PNM	1		—		55		1
PNM to PNMR	28		35		79		113
Income tax sharing payments:
PNMR to PNM	—		—		—		45,000
PNMR to TNMP	—		—		—		—

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(15) Goodwill

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM.

GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. PNMR's reporting units that have goodwill are PNM and TNMP. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit.

GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity would consider macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity would consider the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit's fair value with its carrying amount. An entity should place more weight on the events and circumstances that most affect a reporting unit's fair value or the carrying amount of its net assets. An entity also should consider positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity would evaluate, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis is not required.

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations.

An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units but a quantitative analysis for others. For the annual evaluations performed as of April 1, 2014 and 2013, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit. For the PNM reporting unit, a discounted cash flow methodology was primarily used to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment.

The annual evaluations performed as of April 1, 2014 and 2013 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2014 and 2013 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 30% and 27%. The last quantitative evaluation performed for the TNMP reporting unit on April 1, 2012 indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 26%. Since the April 1, 2014 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill is contained in Note 21 of Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

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

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations for PNMR is presented on a combined basis, including certain information applicable to PNM and TNMP. The MD&A for PNM and TNMP is presented as permitted by Form 10-Q General Instruction H(2). This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. A reference to a “Note” in this Item 2 refers to the accompanying Notes to Condensed Consolidated Financial Statements (Unaudited) included in Item 1, unless otherwise specified. Certain of the tables below may not appear visually accurate due to rounding.

MD&A FOR PNMR

EXECUTIVE SUMMARY

Overview and Strategy

PNMR is a holding company with two regulated utilities serving approximately 751,000 residential, commercial, and industrial customers and end-users of electricity in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP.

Strategic Goals

PNMR is focused on achieving the following strategic goals:

• Earning authorized returns on its regulated businesses

• Maintaining investment grade credit ratings

• Providing a top-quartile total return to investors

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

• Achieving industry-leading safety performance

• Maintaining strong plant performance and system reliability

• Delivering a superior customer experience

• Demonstrating environmental leadership in its business operations

Earning Authorized Returns on Regulated Businesses

PNMR’s success in accomplishing its strategic goals is highly dependent on continued favorable regulatory treatment for its utilities and their strong operating performance. The Company has multiple strategies to achieve favorable regulatory treatment, all of which have as their foundation a focus on the basics: safety, operational excellence, and customer satisfaction, while engaging stakeholders to build productive relationships.

Both PNM and TNMP seek cost recovery for their investments through general rate cases and various rate riders. PNM anticipates filing a general rate case with the NMPRC by the end of 2014. The PUCT has approved mechanisms that allow TNMP to recover capital invested in transmission and distribution projects without having to file a general rate case, which allows for more timely recovery. The PUCT approved TNMP’s requests for additional investments in transmission assets on March 13, 2014 and September 8, 2014. These approvals increase revenues by $7.1 million annually. The NMPRC has approved rate riders for renewable energy and energy efficiency that also allow for more timely recovery of investments and improve the ability to earn authorized returns from PNM’s retail customers.

Recently, PNM completed rate proceedings for all of its FERC regulated transmission customers and for NEC, its largest wholesale generation services customer, which improved PNM’s returns for providing those services. In addition, PNM currently has a pending case before FERC in which it is requesting an increase in rates charged to transmission customers based on a formula rate mechanism. However, the contract to provide power to Gallup, PNM’s second largest customer for wholesale generation services ended on June 29, 2014. Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K and in Note 12.

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

PNM’s 134 MW interest in PVNGS Unit 3 is currently excluded from NMPRC jurisdictional rates. The power generated from that interest is currently sold into the wholesale market and any earnings or losses are attributable to shareholders. While PVNGS Unit 3’s financial results are not included in the authorized returns on its regulated business, it impacts PNM’s earnings and has been demonstrated to be a valuable asset. As part of compliance with the requirements for BART at SJGS discussed below, PNM has requested NMPRC approval to include PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018.

Maintaining Investment Grade Credit Ratings

PNM is committed to maintaining investment grade credit ratings. The credit ratings for PNMR, PNM, and TNMP were set forth under the heading Liquidity in the MD&A contained in the 2013 Annual Reports on Form 10-K. As discussed under the subheading Liquidity in MD&A – Liquidity and Capital Resources below, S&P raised the corporate credit ratings and senior debt ratings for PNMR, PNM, and TNMP, as well as the preferred stock rating for PNM, on April 5, 2013. S&P retained the outlook as stable for all entities. On June 21, 2013, Moody’s changed the ratings outlook for PNMR, PNM, and TNMP to positive from stable. On January 30, 2014, Moody’s raised the credit ratings for PNMR, PNM and TNMP by one notch, while maintaining the positive outlook. On April 30, 2014, S&P changed the outlook for PNMR, PNM, and TNMP to positive from stable. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade.

Providing Top-Quartile Total Returns to Investors

PNMR’s strategic goal to provide top quartile total return to investors over the 2012 to 2016 period is based on five-year ongoing earnings per share growth plus five-year average dividend yield from a group of regulated electric utility companies with similar market capitalization. Top quartile total return currently is equal to an average annual rate of 10% to 13%.

PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. Ongoing earnings, which is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP. The annual common stock dividend was raised by 16% in February 2012, 14% in February 2013, and 12% in December 2013. PNMR expects to provide above-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target. The Board will continue to evaluate the dividend on an annual basis, considering sustainability and growth, capital planning, and industry standards.

Business Focus

In addition to its strategic goals, PNMR’s strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power to create enduring value for customers and communities. To accomplish this, PNMR works closely with customers, stakeholders, legislators, and regulators to ensure that resource plans and infrastructure investments benefit from robust public dialogue and balance the diverse needs of our communities.

Reliable and Affordable Power

PNMR and its utilities are aware of the important roles they play in enhancing economic vitality in their New Mexico and Texas service territories. Management believes that maintaining strong and modern electric infrastructure is critical to ensuring reliability and economic growth. When considering expanding or relocating to other communities, businesses consider energy affordability and reliability to be important factors. PNM and TNMP strive to balance service affordability with infrastructure investment to maintain a high level of electric reliability and to deliver a superior customer experience. 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 ensuring reliability and meeting future energy needs. Both utilities have long-established records of providing customers with reliable electric service.

In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through September 30, 2014, TNMP had completed installation of more than 170,000 smart meters, which is approximately 74% of the anticipated total. TNMP’s deployment is expected to be completed in 2016.

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As part of the State of Texas’ long-term initiative to create a smart electric grid, installation of smart meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. TNMP is currently installing a new outage management system that will leverage capabilities of the smart meters to enhance TNMP’s responsiveness to outages.

During the 2011 to 2013 period, PNM and TNMP together invested $937.5 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. In 2012, PNM announced plans for the 40 MW natural gas-fired La Luz peaking generating station to be located near Belen, New Mexico. In June 2014, the NMPRC approved construction of the La Luz plant. The facility is expected to go into service in late 2015. On July 17, 2014, PNM completed the purchase of Rio Bravo, formerly known as Delta, a 132 MW gas-fired peaking facility, which has served PNM jurisdictional needs under a 20-year PPA since 2000.

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3 discussed below. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities.

Environmentally Responsible Power

PNMR has a long-standing record of environmental stewardship. PNMR’s environmental focus has been in three key areas:

• Developing strategies to meet regional haze rules at the coal-fired SJGS as cost-effectively as possible while providing broad environmental benefits that also demonstrate progress in addressing proposed new federal regulations for CO₂ emissions from existing power plants

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

•Increasing energy efficiency participation

Another area of emphasis is the reduction of the amount of fresh water used during electricity generation at PNM’s power plants. The fresh water used per MWh generated has dropped by 19% since 2002, primarily due to the growth of renewable energy sources, the expansion of Afton to a combined-cycle plant that has both air and water cooling systems, and the use of gray water for cooling at Luna. As discussed below, PNM has requested approval to shut down SJGS Units 2 and 3, which would reduce water consumption at that plant by about 50%. In addition to the above areas of focus, the Company is also working to reduce the amount of solid waste going to landfills through increased recycling and reduction of waste. The Company has performed well in this area in the past and expects to continue to do so in the future.

Renewable Energy

PNM’s 2013 renewable procurement strategy almost doubled PNM’s existing solar capacity with the addition of 21.5 MW of utility-owned solar capacity. In addition to the solar expansion, the 2013 plan included a 20-year agreement to purchase energy from a geothermal facility built near Lordsburg, New Mexico. The facility began providing power to PNM in January 2014. The current capacity of the facility is 4 MW and future expansion may result in up to 10 MW of generation capacity. PNM’s 2014 renewable procurement strategy calls for the construction of an additional 23 MW of utility-owned solar capacity, a 20-year PPA for the output of an existing 102 MW wind energy center beginning in 2015, and the purchase of RECs in 2014 and 2015 to meet the RPS. PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements include the construction of 40 MW of PNM-owned solar PV facilities in 2015, which are contemplated in PNM’s application to retire SJGS Units 2 and 3 discussed below. PNM expects a decision late in 2014.

In addition to PNM’s utility-owned PV solar facilities, PNM owns the 500 KW PNM Prosperity Energy Storage Project, which uses advanced batteries to store solar power and dispatch the energy either during high-use periods or when solar production is limited. The project features one of the largest combinations of battery storage and PV energy in the nation and involves extensive research and development of smart grid concepts. The facility was the nation’s first solar storage facility fully integrated into a utility’s power grid.

PNM also has a PPA for the output from a 204 MW wind facility and purchases power from a customer-owned distributed solar generation program that had an installed capacity of 30.5 MW at the end of 2013. These renewable resources are key means

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for PNM to meet the RPS and related regulations, which require PNM to achieve prescribed levels of energy sales from renewable sources, if that can be accomplished without exceeding the RCT cost limit set by the NMPRC.

PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM believes its currently planned resources will enable it to comply with the NMPRC’s diversity requirements. PNM will continue to procure renewable resources while balancing the bill impact to customers in order to meet New Mexico’s escalating RPS requirements.

SJGS

PNM continues its efforts to comply with the EPA regional haze rule in a manner that minimizes the cost impact to customers while still achieving broad environmental benefits. Additional information about BART at SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K and in Note 11.

In August 2011, EPA issued a FIP for regional haze that would have required the installation of SCRs on all four units at SJGS by September 2016. Following approval by the majority of the other SJGS owners, PNM, NMED, and EPA agreed, on February 15, 2013, to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a RSIP from the State of New Mexico. The RSIP has been approved by the EIB and EPA.

In December 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. On October 1, 2014, PNM filed a stipulation with the NMPRC that, if approved, would settle this case. The stipulation was agreed to by the staff of the NMPRC, the NMAG, NMIEC, and certain other intervenors. The stipulation was opposed by New Energy Economy and certain other intervenors.

Under the terms of the stipulation, PNM would:

• Retire SJGS Units 2 and 3 at December 31, 2017 and recover over 20 years 50% of their undepreciated book value at that date, after transferring $26 million to SJGS Unit 4, and earn a regulated return on those costs

• Acquire an additional 132 MW of SJGS Unit 4

• Include PNM’s ownership of PVNGS Unit 3 as a resource to serve New Mexico retail customers effective January 1, 2018 at a value of $221.1 million ($1,650 per KW)

• Recover up to $90.6 million of costs for the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4

• Not recover approximately $20 million of increased operations and maintenance expenses and other costs incurred in connection with CAA compliance

There would be no initial cost for PNM to acquire the additional 132 MW of SJGS Unit 4 although PNM’s share of capital improvements, including the costs of installing SNCRs, and operating expenses would increase to reflect the increased ownership.

The public hearing in the NMPRC case is scheduled to begin on January 5, 2015. PNM expects a decision from the NMPRC in the first quarter of 2015. PNM is unable to predict if the NMPRC will approve the stipulation. If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, the write-up of the investment in PVNGS Unit 3 to the amount allowed for recovery, and other impacts of the stipulation. As further described in Note 11, PNM currently estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.

The RSIP would achieve similar visibility improvements as the installation of SCRs on all four units at SJGS at a lower cost to PNM customers. It has the added advantage of reducing other emissions beyond NOx, including SO₂, particulate matter, CO₂, and mercury, as well as reducing water usage.

The December 20, 2013 filing also identified a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. The additional solar capacity is included in PNM’s 2015 renewable procurement strategy. A proposed stipulated settlement, which is pending approval before the NMPRC, would provide that the additional solar capacity be recovered in base rates rather than through the renewable energy rider. Specific approval for the additional gas facility and the treatment of associated costs will be addressed in future filings.

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In connection with the implementation of the revised plan and the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants have expressed a desire to exit their ownership in the plant. As a result, the SJGS participants are attempting to negotiate a restructuring of the ownership in SJGS, as well as addressing the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items.

The non-binding resolution, approved by the SJGS Coordination Committee on June 26, 2014, identifies the participants who would be exiting active participation in SJGS effective December 31, 2017, and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The non-binding resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. The non-binding resolution and term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants will need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. See Coal Supply in Note 11, for additional information. In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the above resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. The Fuel and Capital Funding Agreement is subject to acceptance by FERC. Other definitive agreements among the participants are being negotiated. PNM cannot predict if final agreements will be executed.

A number of regulatory approvals are required to implement the proposed ownership restructuring of SJGS. Final binding agreements relating to the ownership restructuring are subject to the approval of each participant’s board or other decision-making body and are subject to required regulatory approvals. PNM is unable to predict the outcome of the negotiations, whether definitive agreements will be reached among the owners, or whether required approvals will be obtained.

PNM, as the SJGS operating agent, presented the SNCR project to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. PNM is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending resolution by the participants. In March 2014 and again in June 2014, PNM requested that the owners of Unit 4 approve certain expenditures critical to being able to comply with the time frame in the RSIP with respect to Unit 4 project. The Unit 4 owners did not approve either of the requests. Thereupon, PNM issued “Prudent Utility Practice” notices that, under the SJPPA, PNM was continuing certain critical activities to keep the Unit 4 project on schedule.

In addition to the regional haze rule, SJGS is required to comply with other rules currently being developed or implemented that affect coal-fired generating units, including recently proposed rules on GHG under Section 111(d) of the CAA. Because of environmental upgrades completed in 2009, SJGS is well positioned to outperform the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. The major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO₂, particulate matter, and mercury. Since 2006, SJGS has reduced NOx emissions by 41%, SO₂ by 60%, particulate matter by 69%, and mercury by 99%.

Energy Efficiency

Energy efficiency also plays a significant role in helping to keep customers' electricity costs low while continuing to meet their energy needs. PNM's and TNMP's energy efficiency and load management portfolios continue to achieve robust results. In 2013, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 75 GWh. This is equivalent to the annual consumption of approximately 10,200 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 2013 resulted in energy savings totaling an estimated 17 GWh. This is equivalent to the annual consumption of approximately 1,650 homes in TNMP’s service territory.

Creating Value for Customers and Communities

The Company strives to deliver a superior customer experience by understanding the dynamic needs of its customers through ongoing market research, identifying and establishing best-in-class services and programs, and proactively communicating and engaging with customers at a regional and community level. In 2013, PNM refocused its efforts to improve the customer experience through an integrated marketing and communications strategy that encompassed brand repositioning and advertising,

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customer service improvements, and strategic customer and stakeholder engagement. As part of this effort, in February 2014, PNM launched an updated website that provides an increase in self-service options for customers, as well as a mobile platform.

Integrated communication around known satisfaction drivers, including billing and payment options, bill redesign, energy efficiency, and environmental and community stewardship ensured PNM retained traction from prior efforts, as well as gained new ground in critical areas, notably corporate citizenship perceptions. PNM’s perceived value to customers has also improved.

Recognizing the importance of environmental stewardship to customers and other stakeholders, PNM expanded engagement with environmental stakeholders to promote ongoing dialogue and input. Similarly, PNM also proactively communicated with communities about its efforts and plans related to environmental stewardship. Customers took note of PNM’s efforts in this area. A nationally recognized customer satisfaction benchmark revealed gains in awareness of PNM’s efforts to improve environmental impact, as well as customer perceptions around the commitment to preserving the environment now and for future generations.

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

Through outreach, collaboration, and various community-oriented programs, PNMR has a demonstrated commitment to build productive relationships with stakeholders, including customers, regulators, legislators, and intervenors.

Building off work that began in 2008, PNM has continued outreach efforts to connect low-income customers with nonprofit community service providers offering support and help with such needs as utility bills, food, clothing, medical programs, services for seniors, and weatherization. In 2013, PNM hosted 22 community events throughout its service territory to assist low-income customers. Furthermore, the PNM Good Neighbor Fund provided $0.3 million of assistance with utility bills to 3,610 families in 2013. In 2013, PNM committed funding of $0.9 million to the PNM Good Neighbor Fund.

The PNM Resources Foundation helps nonprofits become more energy efficient through Reduce Your Use grants. In 2013, PNMR committed funding of $3.5 million to the PNM Resources Foundation. For 2013, the foundation awarded $0.2 million to support 56 projects in New Mexico to provide shade structure installations, window replacements, and efficient appliance purchases. Since the program’s inception in 2008, Reduce Your Use grants have provided nonprofit agencies in New Mexico with a total of $1.4 million of support. In 2013, in connection with the PNM Resources Foundation’s 30^th anniversary, the foundation awarded thirty $10,000 environmental grants to nonprofit agencies. In 2014, the PNM Resources Foundation launched a new grant program designed to help nonprofit organizations build more vibrant communities.  Power Up Grants in the aggregate amount of $500,000 were awarded to 24 nonprofits in New Mexico and Texas for projects ranging from creating community gathering spaces to revitalizing neighborhood parks to building a youth sports field.

In Texas, community outreach is centered first on local relationships, specifically with community leaders, nonprofit organizations and key customers in areas served by TNMP. Community liaisons serve in each of TNMP's three geographic business areas, reaching out and ensuring productive lines of communication between TNMP and its customer base.

TNMP maintains long-standing relationships with several key nonprofit organizations, including agencies that support children and families in crisis, food banks, environmental organizations, and educational nonprofits, through employee volunteerism and corporate support. TNMP also actively participates in safety fairs and demonstrations in addition to supporting local chambers of commerce in efforts to build their local economies.

TNMP's energy efficiency program provides unique offers to multiple customer groups, including residential, commercial, government, education, and nonprofit customers. These programs not only enable peak load and consumption reductions, particularly important when extreme weather affects Texas' electric system, but they also demonstrate TNMP's commitment to more than just delivering electricity by partnering with customers to optimize their energy usage.

Economic Factors

In the three and nine months ended September 30, 2014, PNM experienced decreases in weather normalized retail load of 0.2% and 1.9% compared to 2013.  New Mexico’s economy still lags the nation in post-recession recovery. In the three and

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nine months ended September 30, 2014, TNMP’s weather normalized retail load increased 1.8% and 3.2% compared to 2013. In recent years, New Mexico and Texas have fared better than the national average in unemployment although the unemployment rate in New Mexico exceeded the national average in September 2014. However, employment growth is a stronger predictor of load. Texas’ employment growth rates are well above the national rate, while New Mexico’s employment remains relatively flat.

Results of Operations

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014		2013		Change
	(In millions, except per share amounts)
Net earnings attributable to PNMR	$	55.7	$	54.6	$	1.1		$	97.3	$	92.9	$	4.4
Average diluted common and common equivalent shares	80.2		80.3		(0.1		)	80.3		80.5		(0.2		)
Net earnings attributable to PNMR per diluted share	$	0.69	$	0.68	$	0.01		$	1.21	$	1.15	$	0.06

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

	Three Months Ended			Nine Months Ended
	September 30, 2014			September 30, 2014
	(In millions)
PNM	$	(2.5	)	$	(12.1	)
TNMP	2.3			6.5
Corporate and Other	1.3			10.0
Net change	$	1.1		$	4.4

PNMR’s operational results were affected by the following:

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

• Rate increases for PNM and TNMP – additional information about these rate increases is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K and Note 12

• Milder weather in 2014 than 2013

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

• Higher prices for sales of power from PVNGS Unit 3

• Increased income tax expense in 2013 due to impairments of state tax credits and a tax rate change in New Mexico that did not recur in 2014 (Note 13)

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

Liquidity and Capital Resources

The Company has revolving credit facilities that provide capacities for short-term borrowing and letters of credit of $300.0 million for PNMR and $400.0 million for PNM, both of which expire in October 2018. In addition, PNM has a $50.0 million revolving credit facility, which expires in January 2018, with banks having a significant presence in New Mexico and TNMP has a $75.0 million revolving credit facility, which expires in September 2018. Total availability for PNMR on a consolidated basis was $814.0 million at October 24, 2014. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. PNMR also has intercompany loan agreements with each of its subsidiaries.

The Company projects that its total capital requirements, consisting of construction expenditures and dividends, will total $2,608.5 million for 2014-2018, including amounts expended through September 30, 2014. The construction expenditures include estimated amounts related to environmental upgrades at SJGS to address regional haze and the identified sources of replacement capacity under the revised plan for compliance described in Note 11. The construction expenditures also include additional

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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. 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 2014-2018 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.

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 3 for more information on PNMR’s operating segments.

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

PNM

The following table summarizes the operating results for PNM:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
	(In millions)
Electric operating revenues	$	335.0		$	326.0		$	9.0		$	873.4		$	863.6		$	9.8
Cost of energy	115.1			100.2			14.9			304.4			283.7			20.7
Margin	219.9			225.8			(5.9		)	569.1			579.9			(10.8		)
Operating expenses	101.8			104.7			(2.9		)	315.7			311.4			4.3
Depreciation and amortization	27.5			25.9			1.6			81.6			77.8			3.8
Operating income	90.6			95.2			(4.6		)	171.7			190.8			(19.1		)
Other income (deductions)	3.7			4.5			(0.8		)	15.0			14.8			0.2
Net interest charges	(20.1		)	(20.1		)	—			(59.9		)	(60.0		)	0.1
Segment earnings before income taxes	74.2			79.6			(5.4		)	126.8			145.6			(18.8		)
Income (taxes)	(25.1		)	(27.7		)	2.6			(42.3		)	(49.2		)	6.9
Valencia non-controlling interest	(3.7		)	(4.1		)	0.4			(11.1		)	(10.9		)	(0.2		)
Preferred stock dividend requirements	(0.1		)	(0.1		)	—			(0.4		)	(0.4		)	—
Segment earnings	$	45.2		$	47.7		$	(2.5	)	$	73.0		$	85.1		$	(12.1	)

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

	2013/2014 Change
	Three Months Ended September 30,									Nine Months Ended September 30,
	Electric									Electric
	Operating			Cost of						Operating			Cost of
	Revenues			Energy			Margin			Revenues			Energy			Margin
	(In millions)
Customer usage	$	(0.3	)	$	—		$	(0.3	)	$	(9.3	)	$	—		$	(9.3	)
Weather	(3.0		)	—			(3.0		)	(8.7		)	—			(8.7		)
FPPAC	13.6			13.6			—			12.5			12.5			—
Economy service	1.5			1.5			—			6.0			5.8			0.2
Rio Bravo purchase	—			(1.3		)	1.3			—			(1.3		)	1.3
Gallup wholesale contract	(1.5		)	(0.3		)	(1.2		)	(0.6		)	(0.3		)	(0.3		)
Renewable energy rider	1.8			0.6			1.2			7.5			2.6			4.9
Energy efficiency rider	1.4			—			1.4			2.9			—			2.9
Unregulated margin	1.1			(0.2		)	1.3			3.4			(2.3		)	5.7
Net unrealized economic hedges	(4.3		)	0.1			(4.4		)	(5.2		)	0.6			(5.8		)
Other	(1.3		)	0.9			(2.2		)	1.3			3.1			(1.7		)
Net change	$	9.0		$	14.9		$	(5.9	)	$	9.8		$	20.7		$	(10.8	)

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2014			2013		Change			2014			2013		Change
	(In millions, except customers)
Residential	$	127.2		$	122.9	$	4.3		$	317.6		$	319.8	$	(2.2	)
Commercial	127.7			119.1		8.6			326.6			319.5		7.1
Industrial	21.3			21.2		0.1			54.4			57.7		(3.3		)
Public authority	8.0			8.2		(0.2		)	19.2			20.0		(0.8		)
Economy service	9.3			7.8		1.5			29.9			23.9		6.0
Other retail	(1.2		)	0.4		(1.6		)	4.0			6.2		(2.2		)
Transmission	9.5			10.5		(1.0		)	28.3			28.5		(0.2		)
Firm-requirements wholesale	8.1			10.1		(2.0		)	30.0			31.0		(1.0		)
Other sales for resale	21.9			18.2		3.7			63.5			52.0		11.5
Mark-to-market activity	3.2			7.6		(4.4		)	(0.1		)	5.0		(5.1		)
	$	335.0		$	326.0	$	9.0		$	873.4		$	863.6	$	9.8
Average retail customers (thousands)	511.4			508.3		3.1			510.6			507.8		2.8

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The following table shows GWh sales by customer class:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014	2013	Change		2014	2013	Change
	(Gigawatt hours)
Residential	936.1	955.8	(19.7	)	2,442.2	2,543.0	(100.8	)
Commercial(1)	1,069.5	1,067.8	1.7		2,942.7	3,001.8	(59.1	)
Industrial	254.6	272.2	(17.6	)	737.2	798.8	(61.6	)
Public authority	74.3	78.4	(4.1	)	189.0	205.0	(16.0	)
Economy service	188.8	174.9	13.9		572.4	528.6	43.8
Firm-requirements wholesale	105.7	157.6	(51.9	)	415.9	484.8	(68.9	)
Other sales for resale	602.0	564.2	37.8		1,725.0	1,592.4	132.6
	3,231.0	3,270.9	(39.9	)	9,024.4	9,154.4	(130.0	)

⁽¹⁾ 2013 numbers reflect an addition of 18.0 GWh, previously included in the three months ended September 30, 2013.

For the three and nine months ended September 30, 2014, retail sales were lower compared to 2013 reflecting a continued sluggish economy in New Mexico. In particular, the Albuquerque metropolitan area continues to lag the nation in economic recovery. Although New Mexico’s economy was not hit as hard by the recession as some other states, it has been reported that Albuquerque is recovering the slowest among the nation’s 100 largest metro areas. For the quarter, employment growth was flat for both New Mexico and Albuquerque and, after an increase in the New Mexico unemployment rate to 7.0% in the first quarter of 2014, the unemployment rate has decreased to 6.6%.  In spite of the economic pressures, PNM experienced year to date average retail customer growth of 0.6%. PNM’s weather normalized retail KWh sales were 0.2% and 1.9% lower for the three and nine months ended September 30, 2014 compared to 2013, which decreased revenues and margin $0.3 million and $9.3 million for the three and nine months ended September 2014. Weather negatively impacted revenues and margin by $3.0 million and $8.7 million during the three and nine months ended September 30, 2014 compared to 2013. Cooling degree days were 4.5% and 7.6% lower for the three and nine months ended September 30, 2014 compared to the same period in 2013. In addition, heating degree days were 13.8% lower for the three months ended March 31, 2014 than in 2013. Cooling degree days only have a minor impact on the first quarter of any year, whereas heating degree days only have a minor impact on the second and third quarter.

PNM implemented new rates for Gallup, its second largest wholesale customer, in July 2013 under a one-year agreement, which improved revenues and margins $0.9 million for the six months ended June 30, 2014 compared to 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility.  PNM’s contract with Gallup ended on June 29, 2014. PNM’s revenues for power sold under the Gallup contract decreased $3.4 million for the three months ended September 30, 2014 compared to 2013. PNM’s revenues for power sold under the Gallup contract totaled $11.7 million during 2013. During the three months ended September 30, 2014, decreases in revenues for the Gallup power contract were partially offset with off-system sales of $1.9 million from the power that would have otherwise been used to serve Gallup and lower fuel expense of $0.3 million.

PNM closed on the acquisition of Rio Bravo, formerly known as Delta, on July 17, 2014. Prior to acquiring Rio Bravo, PNM had a 20 year PPA covering all of the output of the facility, which PNM accounted for as an operating lease and recorded fixed and variable costs in cost of energy. As a result of the Rio Bravo acquisition, cost of energy decreased and margin increased $1.3 million for the three months ended September 30, 2014 compared to 2013. The increase in margin is partially offset by increases in operating and depreciation expenses.

In August 2012, PNM implemented its renewable energy rider, which recovers renewable energy procurement costs to meet the RPS, including the 22 MW of PNM-owned solar PV facilities completed in 2011. In January 2014, PNM increased the rate charged under the rider to include the 21.5 MW of PNM-owned solar PV facilities completed in 2013. See Note 12. For the three and nine months ended September 30, 2014, this rider increased revenues by $1.8 million and $7.5 million. These revenues include a return on investment of $1.2 million and $3.7 million for the three and nine months ended September 30, 2014 compared to $0.7 million and $2.3 million for the three and nine months ended September 30, 2013. Cost of energy, reflecting purchase of RECs and purchase of geothermal power, increased $0.6 million and $2.6 million for the three and nine months ended September 30, 2014. Revenue and margin from PNM’s energy efficiency rider increased $1.4 million and $2.9 million for the three months

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and nine months ended September 30, 2014. Revenues from these riders also recover incremental operating, depreciation, and interest expenses applicable to these programs.

For the three and nine months ended September 30, 2014, unregulated revenue increased $1.1 million and $3.4 million and unregulated margins increased $1.3 million and $5.7 million. The increased revenues are due to higher market prices for power from PVNGS Unit 3. Lower fuel costs due to the discontinuance of DOE spent nuclear fuel charges for PVNGS Unit 3 decreased cost of energy $0.2 million for the three months ended September 30, 2014 compared to 2013. In addition, gas imbalance settlements lowered cost of energy $2.1 million for the nine months ended September 30, 2014 compared to 2013.

Changes in unrealized mark-to-market gains and losses resulted from economic hedges for sales and fuel costs not covered under the FPPAC, primarily associated with PVNGS Unit 3. Unrealized gains of $3.3 million for the three months ended September 30, 2014 compared to unrealized gains of $7.7 million for the three months ended September 30, 2013, decreased margin by $4.4 million. Unrealized gains of $0.1 million for the nine months ended September 30, 2014 compared to unrealized gains of $5.9 million for the nine months ended September 30, 2013, decreased margin by $5.8 million.

As discussed in Note 12, the NMPRC approved the continuation of PNM’s FPPAC and authorized PNM to recover the remaining under-collected balance in its FPPAC balancing account over 18 months effective July 1, 2014. As a result PNM’s revenues increased for the three and nine months ended September 30, 2014 compared to 2013. These revenues were offset in cost of energy with no impact on margin.

PNM provides economy energy services to a major customer. Although KWh sales to this customer increased for the three and nine months ended September 30, 2014 compared to 2013, there is only a minor impact in margin resulting from providing ancillary services. Other changes in revenues and cost of energy for this customer are a pass through with no impact to margin.

For the nine months ended September 30, 2014, other changes in revenue, cost of energy, and margin includes a $1.7 million increase in cost of energy and decrease in margin related to the resolution of issues covered by the arbitration with SJCC discussed in Note 11. As part of the approval of the continuation of PNM’s FPPAC, PNM retains 10% of the revenue from off-system sales that would otherwise be passed through the FPPAC, effective as of July 1, 2013. PNM recorded revenue of $0.2 million and $1.4 million for the three and nine months ended September 30, 2014. The nine months ended September 30, 2014, includes amounts from July 1, 2013 through the NMPRC approval in April 2014. Other also includes the impacts of off-system purchases and sales that are not passed through PNM’s FPPAC.

For the three months ended September 30, 2014, operating expenses decreased $2.9 million compared to 2013. Higher maintenance expenses for outages at Four Corners, PVNGS, and natural gas-fired plants of $0.8 million, $0.3 million and $0.6 million were partially offset by lower outage expenses of $0.3 million at SJGS. Lower labor and employee benefit expenses of $1.4 million and $0.5 million decreased operating expenses for the three months ended September 30, 2014 compared to 2013. Lower property and casualty claims of $0.4 million and lower bad debt expense of $0.3 million decreased operating expenses for the three months ended September 30, 2014 compared to 2013. Higher capitalized administrative and general expenses due to higher capital expenditures decreased operating expenses by $0.9 million. Higher energy efficiency expenses of $1.2 million for the three months ended September 30, 2014, which are recovered through rider revenue as described above, increased operating expenses. In addition, during the three months ended September 30, 2013, PNM concluded that certain costs that had been deferred as regulatory assets were no longer probable of recovery and recorded a regulatory disallowance of $1.7 million increasing operating expenses compared to 2014.

For the nine months ended September 30, 2014, operating expenses increased $4.3 million compared to 2013. Higher maintenance expenses for outages at Four Corners, PVNGS and natural gas-fired plants of $0.7 million, $0.8 million and $2.0 million were partially offset by lower maintenance expenses of $0.8 million at SJGS. Higher energy efficiency and renewable rider expenses of $2.4 million and $0.8 million increased operating expenses for the nine months ended September 30, 2014 compared to 2013. Higher property taxes of $2.0 million due to increased plant in service and higher assessed property values in Arizona and higher bad debt expense of $0.4 million increased operating expenses for the nine months ended September 30, 2014 compared to 2013. Process improvement initiatives increased operating expense $1.9 million for the nine months ended September 30, 2014 compared to 2013. These increases were partially offset by lower labor and employee benefit expenses of $1.6 million and $0.7 million decreasing operating expenses for the nine months ended September 30, 2014 compared to 2013. Lower property and casualty claims of $0.6 million decreased operating expenses for the nine months ended September 30, 2014 compared to 2013. Higher capitalized administrative and general expenses due to higher capital spend decreased operating expenses

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$1.4 million for the nine months ended September 30, 2014 compared to 2013. The regulatory disallowance of $1.7 million in September 2013 further decreased operating expenses in 2014 compared to 2013.

Depreciation and amortization expense increased $1.6 million and $3.8 million for the three and nine months ended September 30, 2014 compared to 2013 due to additions to utility plant in service, including 21.5 MW of PNM-owned solar PV facilities. Depreciation on the PNM-owned solar PV facilities is recovered through the renewable energy rider discussed above.

Other income (deductions) decreased $0.8 million for the three months ended September 30, 2014 and increased $0.2 million for the nine months ended September 30, 2014 compared to 2013. Lower interest income on PVNGS lessor notes of $0.4 million and $1.4 million due to lower outstanding balances decreased interest income for the three and nine months ended September 30, 2014 compared to 2013. Other income (deductions) also reflects the performance of the trusts for nuclear decommissioning and coal mine reclamation, including investment income, gains or losses on sales of investments, management expenses, and taxes paid by the trusts. Pre-tax gains on available-for-sale securities decreased $1.2 million for the three months ended September 30, 2014 and increased $1.3 million for nine months ended September 30, 2014 compared to 2013. In addition, gains of $0.7 million on the disposition of property in 2013 decreased other income (deductions) for the nine months ended September 30, 2014 compared to 2013. PNM recorded expenses of $0.8 million and $1.0 million during the three and nine months ended September 30, 2013 for its commitments to support employment and other economic activities in the "four corners" area, including the Navajo Nation, which did not recur in 2014.

As discussed in Note 13, in September 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008, including the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. As a result of the settlement, PNM recorded an additional income tax expense of $1.1 million in June 2014. An income tax benefit of $1.3 million reflected in the Corporate and Other segment offsets this amount.

TNMP

The following table summarizes the operating results for TNMP:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
	(In millions)
Electric operating revenues	$	79.0		$	73.7		$	5.3		$	215.6		$	201.4		$	14.2
Cost of energy	17.4			14.5			2.9			50.2			41.3			8.9
Margin	61.6			59.2			2.4			165.4			160.1			5.3
Operating expenses	22.3			23.1			(0.8		)	63.7			67.3			(3.6		)
Depreciation and amortization	13.4			13.9			(0.5		)	37.3			37.8			(0.5		)
Operating income	25.9			22.3			3.6			64.4			55.0			9.4
Other income (deductions)	0.8			0.7			0.1			1.5			1.4			0.1
Net interest charges	(6.9		)	(6.7		)	(0.2		)	(20.1		)	(20.7		)	0.6
Segment earnings before income taxes	19.8			16.3			3.5			45.8			35.7			10.1
Income (taxes)	(7.4		)	(6.2		)	(1.2		)	(17.1		)	(13.6		)	(3.5		)
Segment earnings	$	12.4		$	10.1		$	2.3		$	28.7		$	22.2		$	6.5

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

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	2013/2014 Change
	Three Months Ended September 30,								Nine Months Ended September 30,
	Electric								Electric
	Operating			Cost of					Operating			Cost of
	Revenues			Energy		Margin			Revenues			Energy		Margin
	(In millions)
Rate increases	$	1.6		$	—	$	1.6		$	4.5		$	—	$	4.5
Customer usage	0.5			—		0.5			1.1			—		1.1
Customer growth	0.5			—		0.5			1.2			—		1.2
Weather	(1.3		)	—		(1.3		)	(1.2		)	—		(1.2		)
Recovery of third-party transmission costs	2.9			2.9		—			8.9			8.9		—
AMS surcharge	1.4			—		1.4			2.7			—		2.7
CTC surcharge	—			—		—			0.4			—		0.4
Hurricane Ike surcharge	(1.7		)	—		(1.7		)	(4.2		)	—		(4.2		)
Energy efficiency incentive	1.5			—		1.5			1.5			—		1.5
Other	(0.1		)	—		(0.1		)	(0.7		)	—		(0.7		)
Net change	$	5.3		$	2.9	$	2.4		$	14.2		$	8.9	$	5.3

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014		2013		Change		2014		2013		Change
	(In millions, except consumers)
Residential	$	36.6	$	36.4	$	0.2	$	89.5	$	84.1	$	5.4
Commercial	25.1		24.0		1.1		73.5		69.8		3.7
Industrial	3.9		3.2		0.7		11.1		9.6		1.5
Other	13.4		10.1		3.3		41.5		37.9		3.6
	$	79.0	$	73.7	$	5.3	$	215.6	$	201.4	$	14.2
Average consumers (thousands) (1)	238.9		235.3		3.6		237.7		234.7		3.0

⁽¹⁾  TNMP provides transmission and distribution services to REPs that provide electric service to consumers in TNMP’s service territories. The number of consumers above represents the customers of these REPs. Under TECA, consumers in Texas have the ability to choose any REP to provide energy.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014	2013	Change		2014	2013	Change
	(Gigawatt hours)
Residential	938.8	963.6	(24.8	)	2,227.9	2,176.2	51.7
Commercial	731.6	714.7	16.9		1,926.7	1,854.2	72.5
Industrial	715.1	686.1	29.0		2,032.2	1,920.3	111.9
Other	26.5	27.6	(1.1	)	75.9	77.3	(1.4	)
	2,412.0	2,392.0	20.0		6,262.7	6,028.0	234.7

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For the three and nine months ended September 30, 2014, revenues and margin increased by $1.6 million and $4.5 million compared to 2013 due to transmission rate increases in March 2013, September 2013, March 2014, and September 2014. See Note 12. TNMP experienced positive year to date average customer growth of 1.3%, increasing revenues and margin by $0.5 million and $1.2 million for the three and nine months ended September 30, 2014 compared to 2013. Higher weather normalized usage per customer increased revenues and margin by $0.5 million and $1.1 million for the three and nine months ended September 30, 2014 compared to 2013. TNMP’s weather normalized retail KWh sales increased 1.8% and 3.2% for the three and nine months ended September 30, 2014 compared to 2013. Milder weather decreased revenues and margins by $1.3 million and $1.2 million for the three and nine months ended September 30, 2014 compared to 2013. For the three and nine months ended September 30, 2014 compared to 2013, cooling degree days were 4.0% and 3.4% lower. Due to the climate in TNMP’s service territories, variances in cooling degree days have a much larger impact than variances in heating degree days.

Differences between revenues and costs charged by third party transmission providers are deferred and recovered through a transmission cost recovery factor resulting in no impact on margin. Higher transmission cost of energy resulting from rate increases from other transmission service providers within ERCOT increased cost of energy $2.9 million and $8.9 million for the three and nine months ended September 30, 2014 compared to 2013. These increases in cost of energy resulted in TNMP rate increases for the recovery of third party transmission costs increasing revenue by the same amounts.

The AMS surcharge increased revenues and margin by $1.4 million and $2.7 million for the three and nine months ended September 30, 2014 compared to 2013. The CTC surcharge increased revenues and margin by $0.4 million for the nine months ended September 30, 2014 compared to 2013, but was flat for the three months ended September 30. The Hurricane Ike surcharge decreased revenues and margin by $1.7 million and $4.2 million for the three and nine months ended September 30, 2014 compared to 2013. The Hurricane Ike surcharge was terminated in November of 2013 due to full recovery of costs associated with this item. Changes in revenues and margins from these surcharges are offset by changes in operating expenses and depreciation and amortization.

TNMP earned an energy efficiency incentive bonus for having achieved demand savings for the 2013 program year that exceeded its goal. This incentive was approved by the PUCT on September 11, 2014 and increased revenues and margin by $1.5 million for the three and nine months ended September 30, 2014. See Note 12.

Operating expenses decreased $0.8 million and $3.6 million for the three and nine months ended September 30, 2014 compared to 2013. Lower employee healthcare claims of $0.6 million and $1.7 million decreased operating expense for the three and nine months ended September 30, 2014 compared to 2013. Higher capitalization of administrative and general expenses related to higher levels of construction expenditures decreased operating expenses by $0.4 million and $1.4 million for the three and nine months ended September 30, 2014 compared to 2013. Property and casualty claims and vegetation management costs decreased $0.4 million and $0.3 million for the nine months ending September 30, 2014 compared to 2013, but were flat for the three months ended September 30. These decreases were partially offset by higher operating expenses associated with the AMS deployment, which are recovered through the AMS surcharge, of $0.3 million for the three and nine months ended September 30, 2014 compared to 2013.

Depreciation and amortization decreased $0.5 million for the three and nine months ended September 30, 2014 compared to 2013. Depreciation expense associated with the AMS deployment, which is recovered through the AMS surcharge, increased $0.6 million and $1.6 million for the three and nine months ended September 30, 2014 compared to 2013 due to increased AMS deployment. Amortization expense associated with the CTC, which is recovered through the CTC surcharge, increased $0.1 million and $0.6 million for the three and nine months ended September 30, 2014 compared to 2013. In addition, an increase in utility plant in service increased depreciation by $0.4 million and $1.2 million for the three and nine months ended September 30, 2014 compared to 2013. These increases were offset by lower amortization of the Hurricane Ike costs of $1.6 million and $3.9 million for the three and nine months ended September 30, 2014 compared to 2013.

Interest charges increased $0.2 million for the three months ended September 30, 2014 compared to 2013. The issuance of $80.0 million of long-term debt under the TNMP 2013 Bond Purchase Agreement on June 27, 2014 increased interest charges $0.8 million, offset by lower interest charge of $0.5 million due to the maturity of $50.0 million of debt under the TNMP 2011 Term Loan Agreement. See Note 9. Interest charges decreased $0.6 million for the nine months ended September 30, 2014 compared to 2013, primarily due to the April 2013 exchange of $93.2 million of TNMP’s 9.5% First Mortgage Bonds for an equal amount of a new series of 6.95% First Mortgage Bonds offset by the impact of the June 2014 refinancing.

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Corporate and Other

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
	(In millions)
Total revenues	$	—		$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—			—
Margin	—			—			—			—			—			—
Operating expenses	(3.7		)	(3.3		)	(0.4		)	(10.2		)	(10.2		)	—
Depreciation and amortization	3.3			3.0			0.3			9.5			9.6			(0.1		)
Operating income	0.3			0.3			—			0.7			0.6			0.1
Other income (deductions)	(0.6		)	(3.5		)	2.9			(1.6		)	(7.5		)	5.9
Net interest charges	(3.2		)	(3.6		)	0.4			(9.6		)	(11.6		)	2.0
Segment earnings (loss) before income taxes	(3.4		)	(6.8		)	3.4			(10.4		)	(18.6		)	8.2
Income (taxes) benefit	1.5			3.6			(2.1		)	6.0			4.1			1.9
Segment earnings (loss)	$	(1.9	)	$	(3.2	)	$	1.3		$	(4.4	)	$	(14.4	)	$	10.0

Operating expenses for Corporate and Other are net of amounts allocated to PNM and TNMP under shared service agreements. Changes in depreciation and amortization are offset in operating expenses as a result of allocation of these costs to other business segments. Changes in depreciation and amortization primarily relate to the timing of the retirement and installation of certain items of computer software and changes in the allocation of certain items to PNM and TNMP.

The changes in other income (deductions) during the three and nine months ended September 30, 2014 compared to 2013 is due to amortization related to corporate investments that became fully amortized in 2013 and premiums paid on the 2013 repurchase of $23.8 million principal amount of PNMR’s 9.25% Senior Unsecured Notes, Series A, due 2015 that did not recur in 2014. Net interest charges decreased primarily due to lower interest charges resulting from the 2013 debt repurchase. The remaining decrease in net interest charges is the result of lower borrowings and lower interest rates on short-term borrowings.

During the first six months of 2013, income (taxes) benefit for Corporate and Other included the impairment of New Mexico wind energy production tax credits of $3.9 million, after federal income tax benefits, and an expense of $1.2 million due to reductions in Corporate and Other’s deferred tax assets resulting from legislation reducing New Mexico Corporate income tax rates. As discussed in Note 13, in June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008, including the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. At that time, an income tax benefit of $1.3 million was reflected in Corporate and Other as a result of the settlement. An additional income tax expense of $1.1 million reflected in the PNM segment offsets this amount. The remaining change in income (taxes) benefit result from income tax benefits of $0.9 million related to amendments of state and federal income tax returns during the three months ended September 30, 2014, the expiration of certain tax credits in 2013, and lower tax benefits due to lower segment losses before income taxes.

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LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR’s cash flows for the nine months ended September 30, 2014 compared to September 30, 2013 are summarized as follows:

	Nine Months Ended September 30,
	2014			2013			Change
	(In millions)
Net cash flows from:
Operating activities	$	326.2		$	311.0		$	15.2
Investing activities	(311.7		)	(211.4		)	(100.3		)
Financing activities	11.3			(75.1		)	86.4
Net change in cash and cash equivalents	$	25.9		$	24.5		$	1.4

The decreases in PNMR’s cash flow from operation activities relate primarily to $92.9 million lower net tax refunds in the nine months ended September 30, 2014 than in 2013 offset by $60.9 million lower contributions to the PNM and TNMP pension and other post retirement benefit plans in 2014 than in 2013. In addition, refunds to customers of $15.2 million in 2013 related to the settlement of PNM’s transmission rate case did not recur in 2014. Lower retail load at PNM was offset by higher retail load and rate increases at TNMP and other changes in assets and liabilities resulting from normal operations.

The changes in PNMR’s cash flows from investing activities relate primarily to an increase of $59.4 million in utility plant additions in the nine months ended September 30, 2014 compared to 2013. Utility plant additions at PNM were $35.1 million higher in the nine months ended September 30, 2014 compared to 2013, including increases in transmission and distribution additions of $31.2 million and nuclear fuel purchases of $6.8 million. These increases were offset by lower renewable plant additions of $3.1 million. TNMP utility plant additions increased $21.5 million in the nine months ended September 30, 2014 compared to 2013, including increases in transmission and distribution additions of $20.8 million and AMS additions of $0.7 million. Corporate plant additions increased by $2.8 million in 2014 which were partially offset by payments made in 2013 for renovations of the corporate headquarters building. Investing activities in 2014 also includes $36.2 million for the acquisition of Rio Bravo as discussed in Note 5.

The changes in PNMR’s cash flows from financing activities include a $2.5 million reduction in net short-term borrowings in the nine months ended September 30, 2014 compared to 2013. Long-term borrowings in 2014 include the $175.0 million PNM 2014 Term Loan Agreement, which was used to repay amounts under the existing PNM Term Loan Agreement and other short-term borrowings. In addition, 2014 includes the issuance of $80.0 million in long-term debt at TNMP, which was used to repay amounts under the existing TNMP 2011 Term Loan Agreement and other short-term borrowings. In addition, cash paid of $13.0 million in connection with TNMP debt exchange in 2013 did not recur in 2014.

Financing Activities

See Note 6 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K and Note 9 for additional information concerning the Company’s financing activities. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. 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

• Conditions in the financial markets

• Credit ratings

On March 5, 2014, PNM entered into the $175.0 million PNM 2014 Term Loan Agreement and used a portion of the funds borrowed thereunder to repay all amounts outstanding under the existing $75.0 million PNM Term Loan Agreement. The funds

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were also used to repay other short-term amounts outstanding. There were no prepayment penalties paid in connection with the termination of the PNM Term Loan Agreement. The PNM 2014 Term Loan Agreement includes customary covenants and conditions. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.10% at September 30, 2014, and must be repaid on or before September 4, 2015. At September 30, 2014, the weighted average interest rate was 1.01% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2014.

On June 27, 2014, TNMP issued $80.0 million aggregate principal amount of 4.03% first mortgage bonds, due 2024 pursuant to the TNMP 2013 Bond Purchase Agreement dated December 9, 2013. TNMP used $50.0 million of the proceeds to repay the full outstanding amount of the TNMP 2011 Term Loan Agreement and used the remaining $30.0 million of proceeds to reduce short-term debt.

PNMR, PNM, and TNMP are subject to debt-to-capital ratio requirements of less than or equal to 65%.  These ratios for PNMR and PNM include the present value of payments under the PVNGS and EIP leases as debt.

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 expenditures for compliance with environmental requirements and for renewable energy resources

• Expanding the electric transmission and distribution systems

• Purchasing nuclear fuel

Projected capital requirements, including amounts expended through September 30, 2014, are:

	2014		2015-2018		Total
	(In millions)
Construction expenditures	$	509.3	$	1,801.9	$	2,311.2
Dividends on PNMR common stock	58.9		235.8		294.7
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	568.7	$	2,039.8	$	2,608.5

The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above include estimated amounts of $88.5 million related to environmental upgrades at SJGS to address regional haze and $268.3 million related to the identified sources of replacement capacity under the revised plan for compliance described in Note 11. The above construction expenditures also include additional renewable resources anticipated to be required to meet the RPS, additional peaking resources to meet needs outlined in PNM’s current IRP, environmental upgrades at Four Corners of $80.3 million, the purchase of the leased portion of the EIP and the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases, and the purchase of Rio Bravo. Expenditures for the SJGS and Four Corners environmental upgrades are estimated to be $10.2 million in 2014. See Note 11 and Commitments and Contractual Obligations below. The ability of PNMR to pay dividends on its common stock is dependent upon the ability of PNM and TNMP to be able to pay dividends to PNMR. Note 5 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP.

During the nine months ended September 30, 2014, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements and borrowings under the PNM 2014 Term Loan Agreement and the TNMP 2013 Bond Purchase Agreement.

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, including $158.1 million due in the second quarter of 2015 and $175.0 million due in the third quarter of 2015. Note 6 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K contains information about the maturities of long-term debt. The Company has from time to time refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, the Company may refinance other debt issuances, make additional debt repurchases, or enter into other liquidity arrangements in the future.

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Liquidity

PNMR’s liquidity arrangements include the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility that both expire in October 2018 and the TNMP Revolving Credit Facility that expires in September 2018. The PNMR Revolving Credit Facility has a financing capacity of $300.0 million, the PNM Revolving Credit Facility has a financing capacity of $400.0 million, and the TNMP Revolving Credit Facility has a financing capacity of $75.0 million. On January 8, 2014, PNM entered into the $50.0 million PNM New Mexico Credit Facility, which expires on January 8, 2018. The Company believes the terms and conditions of its facilities are consistent with those of other investment grade revolving credit facilities in the utility industry.  Each of the credit facilities contains one financial covenant that requires the maintenance of debt-to-capital ratios of less than or equal to 65%.  For PNMR and PNM, these ratios reflect the present value of payments under the PVNGS and EIP leases as debt.

The revolving credit facilities and the PNM New Mexico Credit Facility provide short-term borrowing capacity. The revolving credit facilities also allow letters of credit to be issued. Letters of credit reduce the available capacity under the facilities. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. The Company’s business is seasonal with more revenues and cash flows from operations being generated in the summer months. In general, the Company relies on the credit facilities to be the initial funding source for construction expenditures. Accordingly, borrowings under the facilities may increase over time. Depending on market and other conditions, the Company will periodically sell long-term debt and use the proceeds to reduce the borrowings under the credit facilities. Borrowings under the PNMR Revolving Credit Facility ranged from zero to $14.5 million during the three months ended September 30, 2014 and from zero to $21.1 million during the nine months ended September 30, 2014. Borrowings under the PNM Revolving Credit Facility ranged from zero to $32.6 million during the three months ended September 30, 2014 and from zero to $82.0 million during the nine months ended September 30, 2014. Borrowings under the PNM New Mexico Credit Facility ranged from zero to $15.0 million during the three months ended September 30, 2014 and from zero to $25.0 million during the nine months ended September 30, 2014. TNMP had no borrowings under the TNMP Revolving Credit Facility during the three months ended September 30, 2014 and borrowings ranged from zero to $30.0 million during the nine months ended September 30, 2014. At September 30, 2014, there were no borrowings under any of these facilities. At September 30, 2014, PNM had $6.5 million and TNMP had $19.1 million in borrowings from PNMR under their intercompany loan agreements.

The Company currently believes that its capital requirements can be met through internal cash generation, existing or new credit arrangements, and access to public and private capital markets. To cover the difference in the amounts and timing of internal cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements. However, if difficult market conditions experienced during 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 could 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 2014-2018 period. This could include debt refinancing, new debt issuances, and/or new equity.

The credit ratings for PNMR, PNM, and TNMP were set forth under the heading Liquidity in the MD&A contained in the 2013 Annual Reports on Form 10-K. On January 30, 2014, Moody’s raised the senior unsecured rating for PNMR, the senior unsecured and issuer ratings for PNM, and the senior secured and issuer ratings for TNMP. Moody’s continued to maintain the ratings outlook for PNMR, PNM, and TNMP as positive. On April 30, 2014, S&P changed the outlook for PNMR, PNM, and TNMP to positive from stable. As of October 24, 2014, ratings on the Company’s securities were as follows:

	PNMR	PNM	TNMP
S&P
Senior secured debt	*	*	A-
Senior unsecured debt	BBB-	BBB	*
Preferred stock	*	BB+	*
Moody’s
Senior secured debt	*	*	A2
Senior unsecured debt	Baa3	Baa2	*
Preferred stock	*	Ba2	*

* Not applicable

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

A summary of liquidity arrangements, which do not include the PNMR Term Loan Agreement or the PNM 2014 Term Loan Agreement, as of October 24, 2014 is as follows:

	PNMR Separate		PNM Separate		TNMP Separate		PNMR Consolidated
	(In millions)
Financing capacity:
Revolving credit facility	$	300.0	$	400.0	$	75.0	$	775.0
PNM New Mexico Credit Facility	—		50.0		—		50.0
Total financing capacity	$	300.0	$	450.0	$	75.0	$	825.0
Amounts outstanding as of October 24, 2014:
Revolving credit facility	$	—	$	—	$	—	$	—
PNM New Mexico Credit Facility	—		—		—		—
Letters of credit	7.7		3.2		0.1		11.0
Total short-term debt and letters of credit	7.7		3.2		0.1		11.0
Remaining availability as of October 24, 2014	$	292.3	$	446.8	$	74.9	$	814.0
Invested cash as of October 24, 2014	$	23.1	$	—	$	—	$	23.1

The above table excludes intercompany debt. As of October 24, 2014, PNM had $7.4 million and TNMP had $25.7 million in borrowings from PNMR under their intercompany loan agreements. 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.

PNMR can offer new shares of common stock through the PNM Resources Direct Plan under a SEC shelf registration statement that expires in August 2015. PNM has a shelf registration statement for up to $500.0 million of senior unsecured notes that expires in May 2017.

Off-Balance Sheet Arrangements

PNMR’s off-balance sheet arrangements include PNM’s operating lease obligations for PVNGS Units 1 and 2 and the EIP transmission line. These arrangements help ensure PNM the availability of lower-cost generation needed to serve customers. Rio Bravo, formerly known as Delta, was an off-balance sheet arrangement prior to its acquisition in July 2014. See MD&A – Off-Balance Sheet Arrangements and Notes 7 and 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K. See Note 5 and Note 6 for additional information concerning the PVNGS Leases and Rio Bravo.

Commitments and Contractual Obligations

PNMR, PNM, and TNMP have contractual obligations for long-term debt, operating leases, construction expenditures, purchase obligations, and certain other long-term obligations. See MD&A – Commitments and Contractual Obligations in the 2013 Annual Reports on Form 10-K.

Contingent Provisions of Certain Obligations

As discussed in the 2013 Annual Reports on Form 10-K,PNMR, PNM, and TNMP have a number of debt obligations and other contractual commitments that contain contingent provisions. Some of these, if triggered, could affect the liquidity of the Company. In the unlikely event that the contingent requirements were to be triggered, PNMR, PNM, or TNMP could be required to provide security, immediately pay outstanding obligations, or be prevented from drawing on unused capacity under certain credit agreements. The contingent provisions also include contractual increases in the interest rate charged on certain of the Company’s short-term debt obligations in the event of a downgrade in credit ratings. The Company believes its financing

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arrangements are sufficient to meet the requirements of the contingent provisions. No conditions have occurred that would result in any of the above contingent provisions being implemented.

Capital Structure

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

	September 30, 2014		December 31, 2013
PNMR
PNMR common equity	47.7	%	48.8	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	52.0	%	50.9	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	47.2	%	48.2	%
Preferred stock	0.4	%	0.4	%
Long-term debt	52.4	%	51.4	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	58.5	%	59.9	%
Long-term debt	41.5	%	40.1	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

According to EPA, gases that trap heat in the atmosphere are called greenhouse gases. The four primary greenhouse gases are CO₂, methane, nitrous oxide, and fluorinated gases, including chlorofluorocarbons such as Freon. In 2013, GHG associated with PNM’s interests in its generating plants were approximately 7.0 million metric tons of CO₂, which comprises the vast majority of PNM’s GHG.  By comparison, the total GHG in the United States in 2012, the latest year for which EPA has published this data, were approximately 6.5 billion metric tons, of which approximately 5.4 billion metric tons were CO₂. 

PNM has several programs underway to reduce or offset GHG from its resource portfolio, thereby reducing its exposure to climate change regulation. See Note 12. In 2011, PNM completed construction of 22 MW of utility-scale solar generation located at five sites on PNM’s system throughout New Mexico. In 2013, PNM expanded its renewable energy portfolio by constructing 21.5 MW of utility-scale solar generation. On December 18, 2013, the NMPRC approved PNM’s 2014 renewable energy procurement plan that includes construction of an additional 23 MW of utility-scale solar generation. This additional generation is anticipated to be online by the end of 2014. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and will purchase the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW, beginning in January 2015. PNM has signed a 20-year PPA for the output of Lightning Dock Geothermal, which began providing power to PNM in January 2014. The current capacity of the facility is 4 MW and future expansion may result in up to 10 MW of generation capacity. Additionally, PNM has a customer distributed solar generation program that represented 30.5 MW at the end of 2013 and is expected to grow to over 39 MW by the end of 2014. Once fully subscribed, the distributed solar programs will reduce PNM’s production from fossil-fueled electricity generation by 117 GWh per year. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a 2014 budget of $22.5 million. PNM estimates these programs saved approximately 75 GWh of electricity in 2013. Over the next 20 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 13,565 GWh of electricity,

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which will avoid at least 6.8 million metric tons of CO₂ based upon projected emissions from PNM’s system-wide resources. These estimates are subject to change because of the high uncertainty of many of the underlying variables, including changes in demand for electricity, and complex interrelationships between those variables.

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

As of December 31, 2013, approximately 74.7% of PNM’s generating capacity, including resources owned, leased, and under PPAs, all of which is located within the United States, consisted of coal or gas-fired generation that produces GHG. Based on current forecasts, the Company does not expect its output of GHG from existing sources to increase significantly in the near-term. Many factors affect the amount of GHG emitted. For example, if new natural gas-fired generation resources are added to meet increased load as anticipated in PNM’s current IRP, GHG would be incrementally increased. In addition, plant performance could impact the amount of GHG emitted. If PVNGS experienced prolonged outages, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG. As described in Note 11, on February 15, 2013, PNM, NMED, and EPA agreed to pursue a strategy to address the regional haze requirements of the CAA at the coal-fired SJGS, which would include the shutdown of SJGS Units 2 and 3. The shutdown of Units 2 and 3 would result in a reduction of GHG of approximately 50% at SJGS. That agreement also contemplates that gas-fired generation would be built to partially replace the retired capacity. Although replacement power strategies potentially include some gas-fired generation, the reduction in GHG from the retirement of the coal-fired generation would be far greater than the increase in GHG from replacement generation. In September 2013, the EIB approved a RSIP submitted by NMED that encompassed the February 15, 2013 agreement and the RSIP was submitted to EPA for approval on October 18, 2013. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and will become effective on November 10, 2014. Because of PNM’s dependence on fossil-fueled generation, any legislation or regulation that imposes a limit or cost on GHG could impact the cost at which electricity is produced. While PNM expects to recover that cost through rates, the timing and outcome of proceedings for cost recovery are uncertain. In addition, to the extent that any additional costs are recovered through rates, customers may reduce their usage, relocate facilities to other areas with lower energy costs, or take other actions that ultimately will adversely impact PNM.

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

EPA Regulation

In April 2007, the United States Supreme Court held that EPA has the authority to regulate GHG under the CAA.  This decision heightened the importance of this issue for the energy industry.  In December 2009, EPA released its endangerment finding 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 was to “tailor” the applicability of two programs, PSD and Title V operating permit programs, to avoid impacting millions of small GHG emitters. The rule focused on the largest sources of GHG, including fossil-fueled electric generating units. This program covered 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 would be subject to PSD permitting requirements, even if they did not significantly increase emissions of any other pollutant. As a result, PNM’s fossil-fueled generating plants were more likely to trigger PSD permitting requirements because of the magnitude of GHG. However as discussed below, a recent court case has now limited the extent of the Tailoring Rule.

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On June 26, 2012, the D.C. Circuit rejected challenges to EPA’s 2009 GHG endangerment finding, GHG standards for light-duty vehicles, PSD Interpretive Memorandum (EPA’s so-called GHG “Timing Rule”), and the Tailoring Rule. The Court found that EPA’s endangerment finding and its light-duty vehicle rule “are neither arbitrary nor capricious,” that “EPA’s interpretation of the governing CAA provisions is unambiguously correct,” and that “no petitioner has standing to challenge the Timing and Tailoring Rules.” On October 15, 2013, the United States Supreme Court granted a petition for a Writ of Certiorari regarding the permitting of stationary sources that emit GHG. The Supreme Court limited the question that it would review to: “Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases.” Specifically, the case deals with whether EPA’s determination that regulation of GHG from motor vehicles required EPA to regulate stationary sources under the PSD and Title V permitting programs. The petitioners argued that EPA’s determination that it was required to regulate GHG under the PSD and Title V Programs was unlawful as it violates Congressional intent.

On June 23, 2014, the United States Supreme Court issued its opinion on the above case. The Supreme Court largely reversed the D.C. Circuit. First, the Supreme Court found the CAA does not compel or permit EPA to adopt an interpretation of the act that requires a source to obtain a PSD or Title V permit on the sole basis of its potential GHG. Second, EPA had argued that even if it was not required to regulate GHGs under the PSD and Title V programs, the Tailoring Rule was nonetheless justified on the grounds that it was a reasonable interpretation of the CAA. The Supreme Court rejected this argument. Third, the Supreme Court found EPA lacked authority to "tailor" the CAA's unambiguous numerical thresholds of 100 or 250 tons per year. Fourth, the Supreme Court found that it would be reasonable for EPA to interpret the CAA to limit the PSD program for GHGs to "anyway" sources – those sources that have to comply with the PSD program for other non-GHG pollutants. The Supreme Court said that EPA needed to establish a de minimis level below which BACT would not be required for "anyway" sources.

On March 27, 2012, EPA issued its proposed carbon pollution standards, under Section 111(b) of the CAA, for GHG from new fossil-fueled EGUs larger than 25 MW. The proposed limit was based on the performance of natural gas combined cycle technology. Therefore, coal-fired power plants would only be able to comply with the standard by using carbon capture and sequestration technology. The proposed rule included an exemption for new simple cycle EGUs. EPA accepted comment on the proposed rule through June 25, 2012, during which EPA received over 2.5 million comments. As a result of the comments, EPA reproposed the EGU NSPS as discussed below.

On June 25, 2013, President Obama announced the President’s Climate Action Plan which outlines how his administration plans to cut GHG in the United States, prepare the country for the impacts of climate change, and lead international efforts to combat and prepare for global warming. The plan proposes actions that would lead to the reduction of GHG by 17% below 2005 levels by 2020. The President also issued a Presidential Memorandum to EPA to continue development of the GHG NSPS regulations for electric generators. The Presidential Memorandum establishes a timeline for the reproposal and issuance of a GHG NSPS for new sources and a timeline for the proposal and final rule for developing carbon pollution standards, regulations, or guidelines for GHG reductions from existing sources under Section 111(d) of the CAA.

The Presidential Memorandum further directs EPA to allow the use of “market-based instruments” and “other regulatory flexibilities” to ensure standards will allow for continued reliance on a range of energy sources and technologies and that they are developed and implemented in a manner that provides for reliable and affordable energy and to undertake the rulemaking through direct engagement with states, “as they will play a central role in establishing and implementing standards for existing power plants,” and with utility leaders, labor leaders, non-governmental organizations, tribal officials, and other stakeholders.

EPA met the President’s timeline for the reproposal of the GHG NSPS for new sources (under Section 111(b) of the CAA) by releasing the draft rule on September 20, 2013. In accordance with the Presidential Memorandum, EPA will issue a final rule in “a timely fashion thereafter.” The projected release date of the final rule is January of 2015.

EPA’s reproposed GHG NSPS for new sources applies only to new fossil-fired EGUs. The reproposed standards, based on the size of the unit, would revise requirements for new fossil-fired utility boilers, integrated gasification combined cycle units, combined and simple cycle turbines, and new sources meeting certain other criteria. New coal-fired facilities would only be able to meet the standard by using partial carbon capture and sequestration technology. The reproposed GHG NSPS removed the blanket exemption for simple-cycle turbines and instead provided an exemption for units that sell to the transmission grid less than one-third of their potential electric output over a three-year rolling average.

The Presidential Memorandum directed EPA to issue the proposed GHG NSPS for modified and existing EGUs by June 1, 2014 and to issue the final rule by June 1, 2015. On June 2, 2014, EPA released the proposed rule under Section 111(d) of the

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CAA to establish GHG performance standards for existing EGUs. The proposed rule would require state-specific CO₂ emission reduction goals based on EPA’s finding of the best system of emissions reductions (“BSER”). States would be required to meet both an interim goal from 2020 to 2029 and a final goal beginning in 2030. The proposed BSER is based on four “building blocks”: 1) a 6% heat rate improvement to coal-fired generation units; 2) a shift in electrical generation from coal-fired and oil/gas-fired EGUs to natural gas combined cycle units (“NGCCs”) such that the NGCCs are at a 70% utilization rate; 3) substitution of fossil fuel generation with renewable resources and new nuclear facilities, and extension of life of about 6% of existing nuclear plants that may be retired; and 4) increases to demand-side energy efficiency programs. States would be required to develop SIPs to reach the CO₂ emission reduction goals. The SIPs would need to include enforceable CO₂ emission limits that apply to the affected EGUs within the state. EPA is proposing to allow flexibility in how each state achieves the goal including an option to use either a rate-based or mass-based standard and to develop multi-state compliance plans. State SIPs would be due June 30, 2016 with the possibility of an extension to 2017 if a state needs additional time or 2018 if states choose to enter a multi-state approach. Comments on the proposed rule were originally due on or before October 16, 2014, which has been extended to December 1, 2014.

Also on June 2, 2014, EPA proposed carbon pollution standards for modified and reconstructed EGUs. Under the proposal rule there are two alternatives for EGUs: 1) a CO₂ emission limit based on the unit’s best historic annual CO₂ emissions plus an additional 2% reduction or 2) an emission limit dependent on when the unit is modified. Sources modified before becoming subject to a section 111(d) plan would be required to meet an emission limit determined by the unit’s best historical annual CO₂ emission rate plus an additional 2% emission reduction. Units modified after becoming subject to a section 111(d) plan would be required to meet a unit-specific emission limit determined by the section 111(b) implementing authority.

On October 28, 2014, EPA issued a supplemental rule proposing CO₂ emission rates for U.S. territories and areas of Indian country with existing fossil fuel-fired EGUs, as well as guidelines for plans to achieve those rates.  The supplemental proposal would apply to Four Corners, which is located on the Navajo Nation.  With respect to this plant, EPA applied the four building blocks described in its June 18, 2014 CAA Section 111(d) proposal to establish interim and final goals, expressed as CO₂ emission rates.  APS has indicated that if the rule is finalized as proposed, it is unlikely that additional emission reductions would be required as a result of the plant’s past and future actions to comply with the requirements for BART.

EPA regulation of GHG from large stationary sources will impact PNM’s fossil-fueled EGUs. Impacts could involve investments in additional renewables, efficiency improvements, and/or control technologies at the fossil-fueled EGUs. In setting existing source standards, EPA has historically used technology-based performance standards on emission rates. The only end-of-pipe emission control technology for coal and gas fired power plants available for GHG reduction is carbon capture and sequestration, which is not yet a commercially demonstrated technology. There are limited efficiency enhancement measures that may be available to a subset of the existing EGUs; however, such measures would provide only marginal GHG improvements. Additional GHG control technologies for existing EGUs may become viable in the future. The costs of such improvements or technologies could impact the economic viability of some plants.

The ultimate impact of EPA’s regulation of GHG to PNM is unknown because the regulatory requirements, including NSPS requirements, are in draft form and since existing power plants will be regulated by state plans that will not be finalized for several years. PNM estimates that implementation of the RSIP for BART at SJGS, which requires the installation of SNCRs on Units 1 and 4 by the later of January 2016 or 15 months after EPA approval of the RSIP and the retirement of SJGS Units 2 and 3 by the end of 2017, should provide a significant step towards compliance with Section 111(d). PNM is currently reviewing the proposed Section 111(d) rule and is unable to predict the impact of this rule on its fossil fueled generation.

Federal Legislation

Prospects for enactment of legislation imposing a new or enhanced regulatory program to address climate change in Congress are unlikely in 2014 or 2015, although there is growing interest among some policymakers in addressing climate change and there may be legislation in the future.  Instead, EPA is the primary venue for GHG regulation in the near future, especially for coal-fired units. PNM has assessed, and continues to assess, the impacts of potential climate change legislation or regulation on its business.  This assessment is ongoing and future changes arising out of the legislative or regulatory process could impact the assessment significantly.  PNM’s assessment includes assumptions regarding the specific GHG limits, the timing of implementation of these limits, the possibility of a cap and trade program including the associated costs and the availability of offsets, the development of technologies for renewable energy and to reduce emissions, and provisions for cost containment. Moreover, the assessment assumes various market reactions such as the price of coal and gas and regional plant economics.  These assumptions, at best, are preliminary and speculative. However, based upon these assumptions, the enactment of climate change legislation could, among other things, result in significant compliance costs, including large capital expenditures by PNM, and could jeopardize

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the economic viability of certain generating facilities. See Note 11.  In turn, these consequences could lead to increased costs to customers and affect results of operations, cash flows, and financial condition if the incurred costs are not fully recovered through regulated rates. Higher rates could also contribute to reduced usage of electricity.  PNM’s assessment process is ongoing, but too preliminary and speculative at this time for the meaningful prediction of financial impact.

State and Regional Activity

Pursuant to New Mexico law, each utility must submit an IRP to the NMPRC every three years to evaluate renewable energy, energy efficiency, load management, distributed generation, and conventional supply-side resources on a consistent and comparable basis.  The IRP is required to take into consideration risk and uncertainty of fuel supply, price volatility, and costs of anticipated environmental regulations when evaluating resource options to meet supply needs of the utility’s customers.  The NMPRC requires 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 1, 2014 showed that consideration of carbon emissions costs impacted the projected in-service dates of some of the identified resources.  

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

On August 2, 2012, thirty-three New Mexico organizations representing public health, business, environmental, consumers, Native American, and other interested parties filed a petition for rulemaking with the NMPRC. The petition asked the NMPRC to issue a NOPR regarding the implementation of an Optional Clean Energy Standard for electric utilities located in New Mexico. The proposed standard would have utilities that elect to participate reduce their CO₂ emissions by 3% per year. Utilities that opt into the program would be assured recovery of their reasonable compliance costs. On October 4, 2012, the NMPRC held a workshop to discuss the proposed standard and whether it has authority to proceed with the NOPR. On August 28, 2013, the petitioners amended the August 2, 2012 petition and requested that the NMPRC issue a NOPR to implement a “Carbon Risk Reduction Rule” for electric utilities in New Mexico. The proposed rule would require affected utilities to demonstrate a 3% per year CO₂ emission reduction from a three-year average baseline period between 2005 and 2012. The proposed rule would use a credit system that provides credits for electricity production based on how much less than one metric ton of CO₂ per MWh the utility emits. Credits would be retired such that 3% per year reductions are achieved from the baseline year until 2035 unless a participating utility elects to terminate the program at the end of 2023. Credits would not expire and could be banked. An advisory committee of interested stakeholders would monitor the program. In addition, utilities would be allowed to satisfy their obligations by funding NMPRC approved energy efficiency programs. There has been no further action on this matter at the NMPRC.

International Accords

The United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was produced at the United Nations Conference on Environment and Development (informally known as the Earth Summit). Since the UNFCCC entered into force in March 1994, the parties, including the United States, have been meeting annually in Conferences of the Parties (“COP”) to assess progress in dealing with climate change and, beginning in the mid-1990s, to negotiate the Kyoto Protocol to establish legally binding obligations for developed countries to reduce their GHG. Specifically, the objective is to “stabilize greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.” The Company monitors the proceedings of the UNFCCC, including the annual COP meetings, to determine potential impacts to its business activities.  At the COP meeting in 2011, participating nations, including the United States, agreed that in 2015, they would sign an international treaty requiring all nations to begin reducing carbon emissions by 2020. Known as the Durban Platform for Enhanced Action, the new treaty would supplant the Kyoto Protocol, which was adopted in 1997, that targeted only industrialized nations for mandatory climate emission reductions. The Obama administration plans to release its commitment in March of 2015 and the treaty is scheduled to be finalized in late 2015. PNM will continue to monitor the United States participation in international accords. However, the Company believes that the Obama administration’s target will be based on EPA’s current proposals to regulate carbon and that implementation of the RSIP for BART at SJGS should provide a significant step towards compliance with the requirements.

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Transmission Issues

At any given time, FERC has various notices of inquiry and rulemaking dockets related to transmission issues pending. Such actions may lead to changes in FERC administrative rules or ratemaking policy, but have no time frame in which action must be taken or a docket closed with no further action. Further, such notices and rulemaking dockets do not apply strictly to PNM, but will have industry-wide effects in that they will apply to all FERC-regulated entities. PNM monitors and often submits comments taking a position in such notices and rulemaking dockets or may join in larger group responses. PNM often cannot determine the full impact of a proposed rule and policy change until the final determination is made by FERC and PNM is unable to predict the outcome of these matters.

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

During the first quarter of 2011, at the request of PNM and other southwestern utilities, NERC advised all transmission owners and transmission service providers that the implementation of portions of the MOD-029 methodology for “Flow Limited” paths has been delayed until such time as a modification to the standard can be developed that will mitigate the technical concerns identified by the transmission owners and transmission service providers. PNM and other western utilities filed a Standards Action Request with NERC in the second quarter of 2012.

NERC initiated an informal development process to address directives in Order No. 729 to modify certain aspects of the MOD standards, including MOD-001 and MOD-029. The modifications to this standard would retire MOD-029 and require each transmission operator to determine and develop methodology for TTC values for MOD-001.

A final ballot for MOD-001-2 concluded on December 20, 2013 and received sufficient affirmative votes for approval. On February 10, 2014, NERC filed with FERC a petition for approval of MOD-001-2 and retirement of reliability standards MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a, and MOD-030-2. On June 19, 2014, FERC issued a NOPR to approve a new reliability standard. The MOD-001-2 standard will become effective on the first day of the calendar quarter that is 18 months after the date the standard is approved by FERC. MOD-001-2 will replace multiple existing reliability standards and will remove the risk of reduced TTC for PNM and other western utilities.

In July 2011, FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development.  Order 1000 calls for significant changes to the transmission process of WestConnect, an organization of utility companies providing transmission of electricity in the western region that includes PNM.  On October 11, 2012, PNM and other WestConnect participants filed modified versions of Attachment K to their transmission tariffs to meet Order 1000 regional compliance requirements. Thirteen intervention motions were filed, with several objecting to and/or protesting various provisions of the filings submitted by the WestConnect participants. On December 17, 2012, the WestConnect participants filed responses to the issues raised by the intervenors. On March 22, 2013, FERC issued its order regarding PNM’s and six other WestConnect FERC jurisdictional utilities compliance filings. FERC partially accepted many aspects of the filings including the governance structure that gives the transmission owners a veto authority over the regional plan and cost allocations. A major change directed by FERC is the requirement that the cost allocations be binding on identified beneficiaries and that a process be created that will result in a qualified developer being selected. PNM and the other WestConnect FERC jurisdictional entities submitted their regional compliance filings on September 20, 2013 to address and comply with the March 22, 2013 FERC order. On July 11, 2013, the WestConnect participants submitted their cost allocation and inter-regional coordination plan compliance filing between WestConnect and other regions. On September 18, 2014, FERC issued its order regarding PNM’s and six other WestConnect FERC jurisdictional utilities’ compliance filings. The WestConnect members are evaluating the order and will be required to make a compliance filing on or before November 17, 2014 to address its requirements.

Financial Reform Legislation

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Reform Act”), enacted in July 2010, includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading facility. It also includes provisions related to swap transaction reporting and record keeping

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and may impose margin requirements on swaps that are not centrally cleared. The United States Commodity Futures Trading Commission (“CFTC”) has published final rules defining several key terms related to the act and has set compliance dates for various types of market participants. The Dodd-Frank Reform Act provides exemptions from certain requirements, including an exception to the mandatory clearing and swap facility execution requirements for commercial end-users that use swaps to hedge or mitigate commercial risk.  PNM expects to qualify for this exception. PNM also expects to be able to comply with its requirements under the Dodd-Frank Reform Act and related rules within the time frames required by the CFTC. However, as a result of the Dodd-Frank Reform Act and related rules, PNM’s swap activities could be subject to increased costs, including from higher margin requirements. In addition, implementation of, and compliance with, the swaps provisions of the Dodd-Frank Reform Act and related rules by PNM’s swap counterparties could result in increased costs. At this time, PNM cannot predict the ultimate impact the Dodd-Frank Reform Act may have on PNM’s financial condition, results of operations, cash flows, or liquidity.

Other Matters

On March 25, 2013, a petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for utility workers. On April 12, 2013, a second petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for meter technicians, who were not included in the original petition. Approximately 200 employees were covered by the petitions. Elections to determine whether the IBEW would represent the employees were held in May 2013.  The employees voted to unionize through both petitions and contract negotiations have begun. Subsequently, on June 25, 2013, a third petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to include a group of three relay technicians, who were not included in the original petition. In August 2013, the relay technicians voted to unionize and contract negotiations have begun. As of September 30, 2014, TNMP had 190 employees represented by IBEW Local 66. The parties are still in negotiations on a collective bargaining agreement.

See Notes 11 and 12 herein and Notes 16 and 17 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K for a discussion of commitments and contingencies and rate and regulatory matters.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

As of September 30, 2014, there have been no significant changes with regard to the critical accounting policies disclosed in PNMR’s, PNM’s, and TNMP’s 2013 Annual Reports on Forms 10-K. The policies disclosed included unbilled revenues, regulatory accounting, impairments, decommissioning and reclamation costs, derivatives, pension and other postretirement benefits, accounting for contingencies, income taxes, and market risk.

MD&A FOR PNM

RESULTS OF OPERATIONS

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

MD&A FOR TNMP

RESULTS OF OPERATIONS

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

DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

Statements made in this filing that relate to future events or PNMR’s, PNM’s, or TNMP’s expectations, projections, estimates, intentions, goals, targets, and strategies are made pursuant to the Private Securities Litigation Reform Act of 1995.

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Readers are cautioned that all forward-looking statements are based upon current expectations and estimates. PNMR, PNM, and TNMP assume no obligation to update this information.

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

• The ability of PNM and TNMP to recover costs and earn allowed returns in regulated jurisdictions, including treatment of SJGS Units 2 and 3 at the date of their proposed early retirement as contemplated in the stipulated settlement pending before the NMPRC in connection with the RSIP to comply with the regional haze provisions of the CAA

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

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

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

• Physical and operational risks related to climate change and potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit GHG

• 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, competition, and other changes in supply and demand

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

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

• 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

• 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

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

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

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

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

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

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

• Changes in applicable accounting principles or policies

Any material changes to risk factors occurring after the filing of PNMR’s, PNM’s, and TNMP’s 2013 Annual Reports on Form 10-K are disclosed in Item 1A, Risk Factors, in Part II of this Form 10-Q.

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

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SECURITIES ACT DISCLAIMER

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

WEBSITES

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

Our Internet addresses are:

• PNMR: www.pnmresources.com

• PNM: www.pnm.com

• TNMP: www.tnmp.com

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

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

• Corporate Governance Principles

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company manages the scope of its various forms of risk through a comprehensive set of policies and procedures with oversight by senior level management through the RMC. The Board’s Finance Committee sets the risk limit parameters. The RMC has oversight over the risk control organization. The RMC is assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions on an enterprise-wide basis. The RMC’s responsibilities include:

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

• Approving the types of derivatives entered into for hedging

• Reviewing and approving hedging risk activities

• Establishing policies regarding counterparty exposure and limits

• Authorizing and delegating transaction limits

• Reviewing and approving controls and procedures for derivative activities

• Reviewing and approving models and assumptions used to calculate mark-to-market and market risk exposure

• Proposing risk limits to the Board’s Finance Committee for its approval

• Quarterly reporting to the Board’s Audit and Finance Committees on these activities

To the extent an open position exists, fluctuating commodity prices, interest rates, equity prices, and economic conditions can impact financial results and financial position, either favorably or unfavorably. As a result, the Company cannot predict with

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certainty the impact that its risk management decisions may have on its businesses, operating results, or financial position.

Commodity Risk

Information concerning accounting for derivatives and the risks associated with commodity contracts is set forth in Note 7, including a summary of the fair values of mark-to-market energy related derivative contracts included in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2014 and the year ended December 31, 2013, the Company had no commodity derivative instruments designated as cash flow hedging instruments.

Commodity contracts, other than those that do not meet the definition of a derivative under GAAP, and those derivatives designated as normal purchases and normal sales, are recorded at fair value on the Condensed Consolidated Balance Sheets. The following table details the changes in PNMR’s net asset or liability balance sheet position for mark-to-market energy transactions.

	Nine Months Ended
	September 30,
	2014			2013
Economic Hedges	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	3,273		$	1,204
Amount realized on contracts delivered during period	2,005			(306		)
Changes in fair value	(1,938		)	6,164
Net mark-to-market change recorded in earnings	67			5,858
Net change recorded as regulatory assets and liabilities	(166		)	601
Net fair value at end of period	$	3,174		$	7,663

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

Fair Value of Mark-to-Market Instruments at September 30, 2014

	Settlement Dates
	2014		2015		2016
	(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—	$	—
Prices provided by other external sources	586		2,963		(375		)
Prices based on models and other valuations	—		—		—
Total	$	586	$	2,963	$	(375	)

PNM measures the market risk of its long-term contracts and wholesale activities using a Monte Carlo VaR simulation model to report the possible loss in value from price movements. VaR is not a measure of the potential accounting mark-to-market loss. The quantitative risk information is limited by the parameters established in creating the model. The Monte Carlo VaR methodology employs the following critical parameters: historical volatility estimates, market values of all contractual commitments, a three-day holding period, seasonally adjusted and cross-commodity correlation estimates, and a 95% confidence level. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used.

PNM measures VaR for the positions in its wholesale portfolio (not covered by the FPPAC). For the nine months ended September 30, 2014, the high, low, and average VaR amounts were $1.3 million, $0.6 million, and $0.9 million. For the year ended December 31, 2013, the high, low, and average VaR amounts were $1.4 million, $0.6 million, and $0.9 million. At September 30, 2014 and December 31, 2013, the VaR amounts for the PNM wholesale portfolio were $0.9 million and $0.6 million.

The VaR limits, which were not exceeded during the nine months ended September 30, 2014 or the year ended December 31, 2013, represent an estimate of the potential gains or losses that could be recognized on the Company’s portfolios, subject to market

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risk, given current volatility in the market, and are not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market prices, operating exposures, and the timing thereof, as well as changes to the underlying portfolios during the year.

Credit Risk

The Company is exposed to credit risk from its retail and wholesale customers, as well as the counterparties to derivative instruments. The Company conducts counterparty risk analysis across business segments and uses a credit management process to assess the financial conditions of counterparties. The following table provides information related to PNMR’s credit exposure by the credit worthiness (credit rating) and concentration of credit risk for counterparties to derivative transactions. All credit exposures at September 30, 2014 will mature in less than two years.

Schedule of Credit Risk Exposure

September 30, 2014

Rating(1)	Credit Risk Exposure(2)		Number of Counter-parties >10%	Net Exposure of Counter-parties >10%
	(Dollars in thousands)
External ratings:
Investment grade	$	7,408	1	$	6,436
Non-investment grade	—		—	—
Internal ratings:
Investment grade	145		—	—
Non-investment grade	121		—	—
Total	$	7,674		$	6,436

⁽¹⁾  The rating “Investment Grade” is for counterparties, or a guarantor, with a minimum S&P rating of BBB- or Moody’s rating of Baa3. The category “Internal Ratings – Investment Grade” includes those counterparties that are internally rated as investment grade in accordance with the guidelines established in the Company’s credit policy.

⁽²⁾  The Credit Risk Exposure is the gross credit exposure, including long-term contracts (other than firm-requirements wholesale customers), forward sales, and short-term sales. The exposure captures the amounts from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses. Gross exposures can be offset according to legally enforceable netting arrangements but are not reduced by posted credit collateral. At September 30, 2014, PNMR held $0.2 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of September 30, 2014 was $6.4 million.

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

Interest Rate Risk

The majority of the Company’s long-term debt is fixed-rate debt and does not expose earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of PNMR’s consolidated long-term debt instruments would increase by 2.0%, or $41.5 million, if interest rates were to decline by 50 basis points from their levels at September 30, 2014. In general, an increase in fair value would impact earnings and cash flows to the extent not recoverable in rates if all or a portion of debt instruments were acquired in the open market prior to their maturity. At October 24, 2014, PNMR, PNM, and TNMP had no short term debt outstanding under their revolving credit facilities, which allow for a maximum aggregate borrowing capacity of $300.0 million for PNMR, $400.0 million for PNM, and $75.0 million for TNMP. PNM had no borrowings under its $50.0 million PNM New Mexico Credit Facility at October 24, 2014. The revolving credit facilities, the PNM New Mexico Credit Facility, the $175.0 million PNM 2014 Term Loan Agreement, and the $100.0 million PNMR Term Loan Agreement bear interest

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at variable rates, which averaged 1.01% for the PNMR Term Loan Agreement and 1.10% for the PNM 2014 Term Loan Agreement on October 24, 2014, and the Company is exposed to interest rate risk to the extent of future increases in variable interest rates.

The investments held by PNM in trusts for decommissioning and reclamation had an estimated fair value of $235.9 million at September 30, 2014, of which 42.0% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at September 30, 2014, the decrease in the fair value of the fixed-rate securities would be 3.5%, or $3.5 million.

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

Equity Market Risk

The investments held by PNM in trusts for decommissioning and reclamation include certain equity securities at September 30, 2014. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 56.6% of the securities held by various trusts as of September 30, 2014. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $13.4 million.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

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

Changes in internal controls

There have been no changes in each of PNMR’s, PNM’s, and TNMP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, each of PNMR’s, PNM’s, and TNMP’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Notes 11 and 12 for information related to the following matters, for PNMR, PNM, and TNMP, incorporated in this item by reference.

Note 11

• The Clean Air Act – Regional Haze – SJGS

• The Clean Air Act – Regional Haze – Four Corners

• The Clean Air Act – Four Corners BART FIP Challenge

• The Clean Air Act – Regional Haze Challenges

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

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

• WEG v. OSM NEPA Lawsuit

• Navajo Nation Environmental Issues

• Santa Fe Generating Station

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• Continuous Highwall Mining Royalty Rate

• SJCC Arbitration

• Four Corners Severance Tax Assessment

• PVNGS Water Supply Litigation

• San Juan River Adjudication

• Rights-of-Way Matter

• Complaint Against Southwestern Public Service Company

• Navajo Nation Allottee Matters

Note 12

• PNM – Renewable Portfolio Standard

• PNM – Energy Efficiency and Load Management

• PNM – FPPAC Continuation Application

• PNM – Integrated Resource Plan

• PNM – Applications for Approvals to Purchase Rio Bravo

• PNM – Application for Approval of La Luz Generating Station

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

• PNM – Formula Transmission Rate Case

• TNMP – Advanced Meter System Deployment

• TNMP – Energy Efficiency

• TNMP – Transmission Cost of Service Rates

See also Climate Change Issues under Other Issues Facing the Company in MD&A. The third paragraph under State and Regional Activity is incorporated in this item by reference.

ITEM 1A. RISK FACTORS

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in PNMR’s, PNM’s, and TNMP’s Annual Reports on Form 10-K for the year ended December 31, 2013.

ITEM 6. EXHIBITS

3.1	PNMR	Articles of Incorporation of PNMR, as amended to date (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed November 21, 2008)
3.2	PNM	Restated Articles of Incorporation of PNM, as amended through May 31, 2002 (incorporated by reference to Exhibit 3.1.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)
3.3	TNMP	Articles of Incorporation of TNMP, as amended through July 7, 2005 (incorporated by reference to Exhibit 3.1.2 to TNMP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
3.4	PNMR	Bylaws of PNMR, with all amendments to and including December 8, 2009 (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed December 11, 2009)
3.5	PNM	Bylaws of PNM, with all amendments to and including May 31, 2002 (incorporated by reference to Exhibit 3.1.2 to PNM’s Report on Form 10-Q for the fiscal quarter ended June 30, 2002)
3.6	TNMP	Bylaws of TNMP, with all amendments to and including June 18, 2013 (incorporated by reference to Exhibit 3.6 to TNMP’s Current Report on Form 8-K filed June 20, 2013)
10.1	PNM	Amendment No. Six to Underground Coal Sales Agreement executed October 2, 2014 among San Juan Coal Company, PNM, and Tucson Electric Power Company and acknowledged by San Juan Transportation Company

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10.2	PNM	San Juan Generation Station Fuel and Capital Funding Agreement dated September 12, 2014 among PNM, Tucson Electric Power Company, The City of Farmington, New Mexico, M-S-R Public Power Agency, The Incorporated County of Los Alamos, New Mexico, Southern California Public Power Authority, City of Anaheim, Utah Associated Municipal Power Systems, and Tri-State Generation and Transmission Association, Inc.
12.1	PNMR	Ratio of Earnings to Fixed Charges
12.2	PNM	Ratio of Earnings to Fixed Charges
12.3	TNMP	Ratio of Earnings to Fixed Charges
31.1	PNMR	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	PNMR	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.3	PNM	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.4	PNM	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.5	TNMP	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.6	TNMP	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	PNMR	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	PNM	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.3	TNMP	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	PNMR, PNM, and TNMP	XBRL Instance Document
101.SCH	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Schema Document
101.CAL	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURE

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

		PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO TEXAS-NEW MEXICO POWER COMPANY
		(Registrants)
Date:	October 31, 2014	/s/ Thomas G. Sategna
		Thomas G. Sategna
		Vice President and Corporate Controller
		(Officer duly authorized to sign this report)

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EX-10.1

EXHIBIT 10.1

AMENDMENT NO. SIX TO UNDERGROUND COAL SALES AGREEMENT

THIS AMENDMENT NO. SIX TO UNDERGROUND COAL SALES AGREEMENT (“Amendment No. Six”), by and between SAN JUAN COAL COMPANY, a Delaware corporation (referred to herein as “SJCC”) and PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation, and TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (collectively referred to herein as the “Utilities”) (with SJCC and Utilities herein sometimes collectively referred to as “Parties”), further amends that certain Underground Coal Sales Agreement, dated August 31, 2001, as amended (the “UG-CSA”), between SJCC and the Utilities.

RECITALS

WHEREAS, the Utilities are part owners of the four unit San Juan Generating Station (“SJGS”) along with the County of Los Alamos (“Los Alamos”), Utah Associated Municipal Power Systems (“UAMPS”), City of Anaheim (“Anaheim”), Southern California Public Power Authority (“SCPPA”), City of Farmington (“Farmington”), M-S-R Public Power Agency (“MSR”), and Tri-State Generation and Transmission Association, Inc. (“Tri-State”), and all nine owners are collectively referred to as “Owners”, and

WHEREAS, SJCC owns and operates the San Juan Underground Mine (the “UG Mine”) that provides coal for the operation of SJGS, and

WHEREAS, San Juan Transportation Company (“SJTC”) may hold certain assets that have been used in conjunction with coal deliveries to SJGS, and

WHEREAS, SJCC and SJTC are wholly owned subsidiaries of BHP Billiton New Mexico Coal, Inc. (“BBNMC”), and

WHEREAS, on May 12, 2014, the United States Environmental Protection Agency, proposed to approve revisions to the New Mexico Regional Haze State Implementation Plan (“SIP”) that address the Best Available Retrofit Technology requirement for oxides of nitrogen (NO_x) for SJGS, which revised SIP, among other things, requires the shutdown of Units 2 and 3 of SJGS by the end of calendar year 2017, and

WHEREAS, no later than December 31, 2014, the SJGS Owners desire to have as much certainty as reasonably possible about coal pricing for coal sales to SJGS for periods after the Closing Date (as defined herein), and

WHEREAS, the Parties believe that, rather than negotiating a replacement coal supply agreement for the period following December 31, 2017, it is in their mutual best interests to negotiate the terms of a potential Transaction (as defined herein), and

WHEREAS, the Parties desire to have negotiated the material terms of a potential Transaction, including the purchase price, by December 31, 2014, which material terms, should the Parties decide to proceed with the Transaction as set forth herein, will be reflected in the form of a

binding and enforceable Letter of Intent (as defined herein), to be followed by a definitive purchase agreement as soon thereafter as possible, and

WHEREAS, capitalized terms used and not defined in this Amendment No. Six have the meaning set forth in the UG-CSA.

AGREEMENT

NOW THEREFORE, in consideration of the terms, covenants and agreements contained in this Amendment No. Six and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Utilities jointly and severally agree with SJCC as follows:

1. The following language of Section 2.3, “Term” of the UG-CSA, shall be and is hereby deleted:

This Agreement shall expire December 31, 2017, unless such term is extended by mutual written agreement of the Parties.

The deleted language of Section 2.3 is hereby replaced with the following:

This Agreement shall expire December 31, 2017, unless such term is shortened by the terms of the Letter of Intent or the Purchase Agreement (as provided in Section 12.6(A) of the UG-CSA, as amended).

2. Section 2.5 of the UG-CSA is hereby deleted.

3. The following language in Section 12.6(A) of the UG-CSA shall be and is hereby deleted:

In the event the Parties fail to agree to extend this Agreement pursuant to Section 2.5 “Extension”, the Parties have the obligation to negotiate diligently and in good faith with a view to concluding a new agreement for the purchase and sale of coal to be effective commencing at the expiration of this Agreement.

The deleted language of Section 12.6(A) of the UG-CSA is hereby replaced with the following:

SJCC, SJTC and BHP Billiton New Mexico Coal, Inc. (“BBNMC”) and the Utilities will negotiate diligently and in good faith to reach a binding and enforceable letter of intent (the “Letter of Intent”) to include the material terms of a potential Transaction, which diligent and good faith negotiation obligation will terminate as of 5:00pm Farmington, New Mexico time on December 31, 2014 (the “LOI Deadline”); provided that such LOI Deadline shall be extended to no later than 5:00pm Farmington, New Mexico time on March 31, 2015, with the written consent of each of the Parties, which consent shall be provided for so long

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as SJCC, SJTC and BBNMC and the Utilities are continuing to negotiate in good faith towards execution of a Letter of Intent. For purposes of this Agreement, (i) “Transaction” shall mean the acquisition by the Purchaser Parties of SJCC and SJTC, the form of which transaction (assets/liabilities or stock) shall be negotiated by the Parties, and the contemporaneous termination of the UG-CSA (recognizing that the Parties’ post-expiration obligations under the UG-CSA will be addressed appropriately depending on the ultimate structure and terms of the Transaction), and (ii) the “Purchaser Parties” shall mean one or more of the Utilities, an entity directly or indirectly wholly owned exclusively by either or both of the Utilities, or such other entity agreed to by the Parties.

Following execution of the Letter of Intent, the entities party to the Letter of Intent will negotiate diligently and in good faith with one another the material terms of a binding definitive purchase agreement (the “Purchase Agreement”) as soon following execution of the Letter of Intent as practicable but no later than December 31, 2015. In the event a Purchase Agreement is not executed by 5:00pm Farmington, New Mexico time on December 31. 2015, the diligent and good faith negotiation obligation in this Section 12.6(A) shall be deemed to have expired and of no further force and effect.

The Parties anticipate that the Purchase Agreement shall provide for a closing date for the Transaction (the “Closing Date”) of December 31, 2016, unless an earlier date is agreed by the Parties, and such other terms (including escrow, representations and warranties, covenants, conditions precedent, indemnification, etc.) as the parties thereto may agree.

4. If, in the sole judgment of the Utilities, for reasons including, but not limited to, because the purchase price to be paid in the potential Transaction does not result in an economic coal supply for SJGS, the Utilities may elect, prior to the LOI Deadline, to not enter into a Letter of Intent. If the Utilities do not enter into a Letter of Intent or the Purchase Agreement, SJCC will continue to supply coal until December 31, 2017, under the terms of the UG-CSA, as amended.

5. Except as expressly provided in this Amendment No. Six, the UG-CSA, as amended by Amendment Nos. One through Five, shall remain in full force and effect.

[This space intentionally left blank]

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IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed on their behalf by their respective officers, thereunto duly authorized.

Public Service Company of New Mexico

By:     s/ Ronald E. Talbot            

Name:      Ronald E. Talbot            

Title:     SVP and COO                         Date: 01 OCT 2014    

Tucson Electric Power Company

By:     s/ Mark Mansfield            

Name:      Mark Mansfield            

Title:     VP Energy Resources                     Date: 02 OCT 2014    

San Juan Coal Company

By:     s/ Pat Risner                

Name:      Pat Risner                

Title:      President                         Date: 30 Sept 2014    

San Juan Transportation Company and BHP Billiton New Mexico Coal, Inc. hereby execute this Agreement solely for the purpose of acknowledging and agreeing to the obligations specified for each of them in UG-CSA Section 12.6(A), as amended in this Amendment Six, with the understanding that this commitment does not make these entities a party to the UG-CSA for any purpose:

San Juan Transportation Company

By:     s/ Pat Risner                

Name:      Pat Risner                

Title:      President                         Date: 30 Sept 2014    

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BHP Billiton New Mexico Coal, Inc.

By:     s/ Pat Risner                

Name:      Pat Risner                

Title:      President                         Date: 30 Sept 2014    

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EX-10.2

EXHIBIT 10.2

EXECUTION VERSION

SAN JUAN GENERATING STATION

FUEL AND CAPITAL FUNDING AGREEMENT

1.0 PARTIES:

The parties to this San Juan Generating Station Fuel and Capital Funding Agreement (“Funding Agreement”) are: PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation (“PNM”); TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (“TEP”); THE CITY OF FARMINGTON, NEW MEXICO, an incorporated municipality and a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“Farmington”); M-S-R PUBLIC POWER AGENCY, a joint exercise of powers agency organized under the laws of the State of California (“M-S-R”); THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO, a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“LAC”); SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY, a joint exercise of powers agency organized under the laws of the State of California (“SCPPA”); THE CITY OF ANAHEIM, a municipal corporation organized under the laws of the State of California (“Anaheim”); UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS, a political subdivision of the State of Utah (“UAMPS”); and TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC., a Colorado cooperative corporation (“Tri-State”). These parties are the owners in the San Juan Generating Station (“San Juan”), and are hereinafter sometimes referred to individually as a “Participant” and collectively as the “Participants”.

2.0 RECITALS: This Funding Agreement is made with reference to the following facts, among others:

2.1 The San Juan Project Participation Agreement (“SJPPA”), as amended and restated March 23, 2006, replaced and superseded previous project agreements and provides the basis (with any further amendments) for the ongoing operation and management of San Juan through July 1, 2022.

2.2 On January 5, 2011, the U.S. Environmental Protection Agency (“EPA”) issued a proposed Federal Implementation Plan (“FIP”) under the federal Clean Air Act that included a proposed Best Available Retrofit Technology (“BART”) determination for emissions of nitrogen oxides (“NOx”) from San Juan requiring installation of selective catalytic reduction (“SCR”) technology on all four San Juan units.

2.3 On February 15, 2013, PNM, in its capacity as San Juan Operating Agent, EPA and the State of New Mexico executed a non-binding agreement (“EPA Term Sheet”) outlining an alternative BART determination (“BART Alternative”).

2.4 The BART Alternative will require retirement of San Juan Unit 2 and Unit 3 by December 31, 2017 and the installation of selective non-catalytic reduction (“SNCR”) technology on San Juan Unit 1 and Unit 4 no earlier than January 31, 2016.

2.5 On February 12, 2013, the San Juan Coordination Committee approved a resolution supporting PNM in its efforts to effectuate the BART Alternative.

2.6 On September 5, 2013, the State of New Mexico approved the BART Alternative.

2.7 On May 12, 2014, EPA published its proposed rule approving the BART Alternative, initiating a 30-day public comment period, which has expired.

2.8 The EPA process to issue final approval of the BART Alternative and withdraw the FIP is expected to be complete on or around September 29, 2014.

2.9 On March 10, 2014, PNM declared in its capacity as San Juan Operating Agent that it needed to commence studies, analysis, assessments and design related to the installation of the BART Alternative on San Juan Unit 4 in order to comply with the deadlines set forth in the EPA Term Sheet.

2.10 The Participants recognize that modifications to the SJPPA will be necessary to accommodate the retirement of San Juan Units 2 and 3 and to restructure the ownership configuration of San Juan Unit 4.

2.11 On June 26, 2014, the San Juan Coordination Committee adopted a resolution (“Resolution”), defining the principal terms and conditions to effectuate the retirement of San Juan Units 2 and 3 and the restructuring of the ownership configuration of San Juan Unit 4.

2.12 The Participants have commenced negotiations of a formal amendment to the SJPPA (the “San Juan Restructuring Agreement”) to effectuate the Resolution and have determined that such negotiations, and the regulatory review of the terms and conditions of the San Juan Restructuring Agreement, will require significant time and effort and that the San Juan Restructuring Agreement will not be completed before expenditures need to be made to support timely completion of the construction and installation of the BART Alternative.

2.13 The Participants desire to implement certain provisions of the Resolution as soon as possible to allocate the now ongoing costs of the construction and installation of the BART Alternative and other ongoing fuel, capital and restructuring costs, as provided for in this Funding Agreement.

3.0 DEFINITIONS: Except as follows, capitalized terms used in this Funding Agreement shall have the same meanings as in the SJPPA:

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3.1 Agreed Date – January 1, 2015.

3.2 Board – the governing body of a Participant.

3.3 Effective Date – The Proposed Effective Date or such later date as FERC requires in an order accepting this Funding Agreement for filing.

3.4 Exit Date – on or about December 31, 2017, as also defined in Section 1 of the Resolution.

3.5 Exiting Participants – M-S-R, Anaheim, SCPPA and Tri-State.

3.6 FERC – Federal Energy Regulatory Commission.

3.7 Proposed Effective Date – July 1, 2014.

3.8 Remaining Participants – PNM, TEP, Farmington, LAC and UAMPS.

3.9 Restructuring Fee – An amount of $8,800,000, as also defined in Section 2 of the Resolution.

3.10 RUS – Rural Utilities Service.

3.11 Shared Inventory – San Juan Coal Company inventory, force majeure inventory and live inventory, as defined in Appendix A to this Funding Agreement.

4.0 EFFECTIVE DATE AND TERMINATION:

4.1 This Funding Agreement shall be effective as of the Effective Date, subject to the following conditions precedent: (a) FERC acceptance for filing of this Funding Agreement; (b) if Tri-State determines that approval of the RUS is required, the RUS approves this Funding Agreement or is deemed to have approved this Funding Agreement by virtue of the failure of RUS to object to this Funding Agreement within the time prescribed in the Tri-State loan contract with RUS; and (c) none of the Participants has rejected this Funding Agreement pursuant to Section 4.3.

4.2 Within two (2) weeks of execution of this Funding Agreement by all Participants, (a) PNM shall file a copy of this Funding Agreement with the FERC; and (b) if Tri-State determines that approval of the RUS is required, Tri-State shall make all necessary filings with the RUS to obtain such approval. In the filing with FERC, PNM shall request waiver of applicable FERC notice requirements in order to allow this Funding Agreement to become effective as of the Proposed Effective Date, supporting the waiver with an explanation of the time constraints imposed by the BART Alternative, the need for equity and efficiency, and the Participants’ agreement to the Proposed Effective Date. All other Participants shall support or

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not oppose PNM’s FERC filing by the prompt filing at FERC of a certificate or letter of concurrence; by intervening at FERC in support of the filing; or by not taking any action to oppose the filing.

4.3 Following (a) an order by the FERC, (b) a letter or other communication from the RUS, if any, (c) an order, letter or other communication from any other regulatory agency from which approval of this Funding Agreement was not requested, or (d) a notice from a Participant pursuant to Section 4.4(d), the Participants shall each review such order, letter, communication or notice to determine if the FERC, RUS, or such agency or Board has changed or modified a condition or conditions, deleted a condition or conditions, or imposed a new condition or conditions with regard to this Funding Agreement; or has conditioned its approval of this Funding Agreement upon changes or modifications to a condition or conditions, deletion of a condition or conditions or imposition of a new condition or conditions. The Participant receiving such order, letter, communication, or notice shall promptly provide a copy of such order, letter, communication, or notice to the other Participants. Within ten (10) business days after receipt by the other Participants of the copy of the order, letter, communication, or notice the Participants shall indicate to each other in writing their acceptance or rejection of this Funding Agreement based upon any changes, modifications, deletions or new conditions required by the FERC, RUS, any agency having jurisdiction or Board. A failure to notify within said ten (10) day period shall be the equivalent to a notification of acceptance. If any Participant rejects this Funding Agreement because the FERC, RUS, any agency having jurisdiction, or Board has modified a condition, deleted a condition or imposed a new condition in this Funding Agreement, or has conditioned its approval on such a change, modification, deletion or new condition, the Participants will be deemed to have rejected this Funding Agreement, it will not take effect, and the Participants shall attempt, in good faith, to renegotiate the terms and conditions of this Funding Agreement to resolve such changed, modified, deleted or new condition, or explanation for determination not to seek Board approval, to the satisfaction of the Participants within thirty (30) days after the date of such order, letter, communication, or notice and thereafter to obtain requisite regulatory approval of such renegotiated agreement. If a notice and explanation are provided pursuant to Section 4.4(d) communicating and explaining a Participant’s determination not to seek approval of the San Juan Restructuring Agreement, the Participants will follow the good faith renegotiation process outlined above.

4.4 This Funding Agreement shall continue in force and effect until the sooner of (a) December 31, 2017; (b) the effective date of the San Juan Restructuring Agreement (provided that the San Juan Restructuring Agreement includes the payment obligations set forth in Section 5 and 6 of this Funding Agreement); (c) the date on which PNM, after good faith effort, provides notice to the Participants that it has failed to receive a requisite regulatory approval as described in Section 7 of the Resolution (including from the Environmental Protection Agency, the New Mexico Public Regulation Commission or the FERC); or (d) the date on

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which a Participant provides notice to the other Participants that it has failed to receive or will not seek Board approval required to enter into the San Juan Restructuring Agreement (after having adhered to the process set forth in the final sentence of Section 4.3). If a Participant determines that it will not seek Board approval of the San Juan Restructuring Agreement, it shall explain to the Participants why it elected not to seek such approval. Consistent with Section 7(b) of the Resolution, each Participant will either support each other’s filings and approvals or not oppose any such filings or approvals. If this Funding Agreement terminates due to condition (c) or (d) above (either a “Failure to Receive Approval”), then:

4.4.1 The Participants’ responsibilities for Capital Improvements under Section 6 of this Funding Agreement shall revert as of the date of such termination to those in effect under the SJPPA prior to the Effective Date. Payments made and received under Section 6 of this Funding Agreement between the Effective Date and the date this Funding Agreement terminates shall not be returned to the Participants who made such payments.

4.4.2 The Participants shall negotiate in good faith to address the consequences of a Failure to Receive Approval and to reach a resolution that preserves the principles and economics of the Resolution as closely as possible.

4.5 As used in this Section 4.5, “Reversion Date” means January 1, 2016 or such later date upon which the Participants may agree. If the San Juan Restructuring Agreement is not executed before the Reversion Date: (i) PNM will return to the Exiting Participants the Shared Inventory on the Reversion Date and the Exiting Participants will pay to PNM the amount PNM paid for the Shared Inventory; (ii) the Remaining Participants will return the Restructuring Fees as received pursuant to Section 5.4 to the Exiting Participants; and (iii) all Participants’ rights, obligations and responsibilities with respect to fuel will revert to the provisions of the SJPPA prospectively as of the Reversion Date. The payments provided for in subsections (i) and (ii) will occur by January 29, 2016 (or such later date upon which the Participants may agree). Any subsequent sale of all or part of coal inventory by any Participant will require the prior written consent of the other Participants, which consent shall not be unreasonably withheld. The Participants’ rights and obligations under this Section 4.5 survive the termination of this Agreement if termination is due to a Failure to Receive Approval.

5.0 FUEL COSTS: The provisions of Section 23, Fuel Costs, of the SJPPA shall be modified by this Section 5 and by the provisions set forth in Appendix A, Fuel Costs, of this Funding Agreement.

5.1 If any provision of Appendix A conflicts with any provision of Section 23, Fuel Costs, of the SJPPA, the provisions of Appendix A shall prevail.

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5.2 Any net payment(s) to be made or received by Exiting Participants related to relinquishment of Shared Inventory on the Agreed Date, as described in Appendix A, Paragraph (b) and to payment of the Restructuring Fee, shall be allocated as follows:

5.2.1    M-S-R:          32.220%

5.2.2    Anaheim:          11.480%

5.2.3    SCPPA:          47.080%

5.2.4    Tri-State:           9.220%

5.3 Any payment(s) to be made by Remaining Participants related to relinquishment of Shared Inventory on the Agreed Date, as described in Appendix A, Paragraph (b), shall be allocated as follows:

5.3.1    PNM:            100.000%

5.3.2    TEP:             0.000%

5.3.3    Farmington:         0.000%

5.3.4    LAC:             0.000%

5.3.5    UAMPS:          0.000%

5.4 Payment(s) to be received by Remaining Participants related to receipt of the Restructuring Fee described in Appendix A, Paragraph (b), shall be allocated as follows:

5.4.1    PNM             0.000%

5.4.2    TEP             0.000%

5.4.3    Farmington         55.600%

5.4.4    LAC             22.200%

5.4.5    UAMPS         22.200%

5.5 On the Agreed Date, the Exiting Participants shall receive from PNM a payment for Shared Inventory, which payment will be netted against the Restructuring Fee.

6.0 CAPITAL IMPROVEMENTS: The provisions of Section 7, Capital Improvements and Retirements of San Juan Project and Participants’ Solely Owned Facilities, of the SJPPA shall be modified by this Section 6 and by the provisions set forth in Appendix B of this Funding Agreement.

6.1 If any provision of Appendix B conflicts with any provision of Section 7, Capital Improvements And Retirements of San Juan Project And Participants’ Solely Owned Facilities, of the SJPPA, the provisions of Appendix B shall prevail.

6.2 The Remaining Participants are responsible for the Costs of Capital Improvements incurred after the Effective Date and the Exiting Participants have no ownership interest in any such Capital Improvements after the Effective Date.

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Costs of Capital Improvements, and voting rights to approve such Capital Improvements, shall be allocated to the Remaining Participants as follows:

6.2.1 For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:

6.2.1.1 PNM:            64.482%

6.2.1.2 Farmington:        21.290%

6.2.1.3 LAC:             7.200%    

6.2.1.4 UAMPS:         7.028%

6.2.2 For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:

6.2.2.1        PNM:            64.482%

6.2.2.2        Farmington:        21.290%

6.2.2.3        LAC:             7.200%

6.2.2.4        UAMPS:         7.028%

6.2.3 For equipment and facilities common to all of the Units in accordance with the following percentages:

6.2.3.1 PNM:            58.671%

6.2.3.2 TEP:            20.068%

6.2.3.3 Farmington:        12.749%

6.2.3.4 LAC:             4.309%

6.2.3.5 UAMPS:         4.203%

6.3 The Exiting Participants shall pay the Demand Charge described in Appendix B for the use of new Capital Improvements implemented on Unit 4, facilities common to Units 3 and 4, and facilities common to all Units as follows:

6.3.1 M-S-R            71.650%

6.3.2 Anaheim        25.000%

6.3.3 SCPPA             2.800%

6.3.4 Tri-State         0.550%

6.4 The Remaining Participants shall be paid for allowing the Exiting Participants the use of Capital Improvements through the Demand Charge described in Appendix B, and payments received from the Exiting Participants shall be allocated as follows:

6.4.1 PNM:             0.000%

6.4.2 TEP:             0.000%

6.4.3 Farmington:        55.600%

6.4.4 LAC:            22.200%

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6.4.5 UAMPS:        22.200%

6.5 If the Proposed Effective Date and the Effective Date are not the same, payments made after the Proposed Effective Date (but before the Effective Date) by Exiting Participants for Capital Improvements, net of any Demand Charge accrued between the Proposed Effective Date and the Effective Date, shall be trued-up between the Exiting Participants and Remaining Participants within sixty (60) days of the date of FERC acceptance.

6.6 No provision of this Funding Agreement shall establish, or relieve the Exiting Participants of, the obligation, if any, to pay their respective shares of the costs of San Juan decommissioning.

7.0 RELATIONSHIP TO SJPPA: Except as expressly provided herein, this Funding Agreement shall not otherwise modify the SJPPA, which shall remain unchanged and in full force and effect, until modified by the Participants through a written agreement.

8.0 EXECUTION IN COUNTERPARTS: This Funding Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument as if all the Participants to the aggregated counterparts had signed the same instrument. Any signature page of this Funding Agreement may be detached from any counterpart thereof without impairing the legal effect of any signatures thereon and may be attached to any other counterpart of this Funding Agreement identical in form thereto but having attached to it one or more additional pages.

IN WITNESS WHEREOF, the Participants, by their duly authorized representatives, have caused this Funding Agreement to be made as of this 12^th day of September, 2014.

[Signatures are on following pages]

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PUBLIC SERVICE COMPANY

OF NEW MEXICO

By     Chris Olson s/ Chris Olson            

Its     Vice President, PNM Generation        

TUCSON ELECTRIC POWER COMPANY

By     s/ Mark Mansfield                

Its     Mark Mansfield VP Energy Resources    

THE CITY OF FARMINGTON, NEW MEXICO

By     s/ Michael Sims                

Its     Electric Utility Director            

M-S-R PUBLIC POWER AGENCY

s/ Martin R. Hopper

By     Martin R. Hopper                

Its     General Manager                

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By Timothy A. Glasco, P.E. s/ Timothy Glasco

Its     Utilities Manager                

SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By     s/ Ronald E. Davis                

Its     President                    

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APPROVED AS TO FORM:

CITY OF ANAHEIM                    MICHAEL R.W. HOUSTON, CITY ATTORNEY

BY s/ Alison M. Kott 8-12-14    

                            Alison M. Kott, Assistant City Attorney

By     s/ Dukku Lee                    

Its Dukku Lee, Public Utilities General Manager    ATTEST:

By s/ Linda N. Andal        

     Linda N. Andal

                                      City Clerk

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By     s/ Douglas Hunter                

Its     General Manager                

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By     s/ Michael S. McInnes                

Its     Executive Vice President/General Manager    

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EXECUTION VERSION

APPENDIX “A”

TO

SAN JUAN GENERATING STATION

FUEL AND CAPITAL FUNDING AGREEMENT

FUEL COSTS

Fuel Supply:

a. Consistent with Section 5 of the Resolution, for purposes of this Funding Agreement, the Participants agree that there are the following types of inventory available for use at SJGS:

i. Coal tons stockpiled on San Juan Coal Company’s (“SJCC”) property are “SJCC Inventory”;

ii. Coal tons stockpiled on SJGS property, excluding tons in the stack-out piles and in process at the plant, as of the Agreed Date (defined below) are “Force Majeure Inventory”;

iii. Coal tons in stack-out piles and in process at the plant as of the Agreed Date are “Live Inventory”;

iv. SJCC Inventory, Force Majeure Inventory, and Live Inventory, collectively defined as “Shared Inventory,” are those tons that exist as of the Agreed Date that will be allocated by Common Participation Share under the SJPPA (regardless of the status of the current Inventory Allocation Agreement) and relinquished by the Exiting Participants to PNM;

v. Coal tons stockpiled on SJGS property after the Agreed Date as a result of Exiting Participants’ inability to burn their remaining 60% share of the allocated share of the take or pay base tons delivered by SJCC due to unit outages are “Exiting Participants’ New Force Majeure Tons”; and

vi. Coal tons stockpiled on SJGS property after the Agreed Date and prior to the Exit Date that are excess tons delivered by SJCC and not purchased by Exiting Participants are “PNM Transition Inventory”. PNM Transition Inventory, the Exiting Participants’ New Force Majeure Tons and the Force Majeure Inventory will physically be commingled.

b. Relinquishment of Inventory: Exiting Participants will relinquish their Common Participation Shares of Shared Inventory that exists as of the Agreed Date at agreed upon values of: (i) $22.69/ton for Force-Majeure Inventory and Live Inventory and $6.573 million for SJCC Inventory, the total sum of which will be allocated pursuant to Section 5 of this Funding Agreement and netted against the cash portion of the Restructuring Fee. In structuring these inventory arrangements the Participants do not intend to create new

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royalty or tax obligations by any Participant.

i. From the Agreed Date through the Exit Date, Exiting Participants will transfer coal from PNM at the Base Price (as defined in Section 23.4.2.1 of the SJPPA), such Base Price to be trued up annually (credits or debits to be allocated pro rata between base and incremental dollars) and will be relieved of 40% of Exiting Participants’ take or pay base obligations under the SJPPA;

ii. The Base Price will also contain a true-up to reflect a per ton credit dollar-for-dollar as provided to PNM under the Refined Coal Agreements once the Refined Coal Project becomes operational;

iii. Prior to the Exit Date Remaining Participants will nominate to SJCC or its replacement supplier a maximum delivery of 6.8 million tons annually. Additional tons may be nominated by Remaining Participants if the fuel supplier’s invoiced cost to deliver the additional tons does not increase the costs assigned to the nomination of 6.8 million tons;

iv. Exiting Participants will retain voting rights to approve IIA Pricing prior to the Exit Date; and

v. Exiting Participants will agree to dispatch their respective shares of the units subject to unit availability at a minimum of 85% of net availability, mathematically expressed as Minimum Annual Generation = Net Effective Generating Capacity multiplied by Participation Share multiplied by 0.85 multiplied by (Unit 3 Equivalent Availability Factor (“EAF”) for SCPPA and Tri-State or the Unit 4 EAF for M-S-R and Anaheim) multiplied by 8760 hours.

c. All Participants will support invoking the Force Majeure provisions under the UG-CSA; and PNM/TEP will pursue through timely arbitration, if necessary, Force Majeure claims if either Unit 3 or 4 has catastrophic or extended outages. PNM will be obligated to purchase New Force Majeure Tons, if any, from Exiting Participants on the Exit Date at a price of $37.50/ton, plus escalation from the Agreed Date computed on the basis provided in Section 8.6 “Inflation – Deflation Adjustment” of the UG-CSA.

d. New Fuel Supply: The Remaining Participants are responsible for all costs of procuring and developing a post-2017 fuel supply for SJGS and for all associated administrative/consultant costs over the amount of $1.2 million already incurred.

e. Except as specified in this provision the following practices will remain unchanged:

i. Utility Payment Stream (“UPS”): Exiting Participants will continue to pay UPS through the Exit Date at Common Participation Share;

ii. Allocation of any other fuel-related cost chargeable to FERC Account 501 through the Exit Date, including but not limited to, limestone, fuel oil, CCB

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disposal, fuel handling, or start-up or auxiliary power and energy, will not be modified by the terms of this provision; and

iii. Allocation by Common Participation Shares of final reclamation costs billed by SJCC through the Exit Date to the extent that such costs are disembedded from fuel costs in the SJCC Invoices. PNM will work diligently to achieve this as accurately as possible.

f. Mine Force Majeure: In the event of a mine disruption resulting in SJCC being unable or unwilling to meet the delivery requirements in Section 4.2A of the UG-CSA, each Participant agrees to take all commercially reasonable actions to mitigate any related fuel and inventory cost impacts which may include complete curtailments of Unit generation and waiving of obligations to meet Minimum Net Generation requirements under Section 14.3 of the SJPPA. All Participants agree to negotiate in good faith to determine whether or how any remaining fuel and related costs are fairly allocated. If after a commercially reasonable period of negotiations, not to exceed 60-days, the Participants are unable to agree, the provisions of Section 5.b.i through 5.b.v of the Resolution will be amended as follows for the period of the disruption:

i. Shared Inventory and any other SJCC Inventory existing at the time of the disruption will be allocated based on Common Participation Share in a manner substantially similar to the terms of the 2011 Coal Source Allocations Agreement and coal pricing reverts to the provisions of the SJPPA except for the specific pricing provisions below;

ii. To the extent that Exiting Participants have relinquished rights to Shared Inventory pursuant to Section 5.b of the Resolution, such rights to inventory will be reinstated;

iii. If Exiting Participants require delivery of SJCC Inventory, in addition to any applicable charges from SJCC associated with such deliveries they will pay to PNM $16.88/ton for their allocated share of the first 1.442 million tons delivered, and $11.25/ton for any tons required above that;

iv. If Exiting Participants require delivery of Force Majeure Inventory, they will pay PNM $22.69/ton; and

v. Exiting Participants’ New Force Majeure Tons may be used by Exiting Participants without payment to PNM.

g. Termination or Assignment of UG-CSA: In the event the UG-CSA is terminated or assigned to a third party prior to the Exit Date, the Participants will negotiate in good faith to amend Section 5 of the Resolution and this Appendix A to preserve the balance of benefits and burdens described above.

13

EXECUTION VERSION

APPENDIX “B”

TO

SAN JUAN GENERATING STATION

FUEL AND CAPITAL FUNDING AGREEMENT

CAPITAL COST ITEMS AND VOTING

Capital Cost Items and Voting:

a. Remaining Participants will assume all responsibility for the costs of Capital Improvements invoiced after the Effective Date and Exiting Participants shall have no ownership interest in such Capital Improvements. Responsibility for Capital Costs invoiced prior to the Effective Date shall be based on existing ownership of plant or common property.

b. The Unit 3 Exiting Participants (SCPPA, Tri-State) will have no responsibility after the Effective Date for costs of the SNCR/balanced draft project to be placed on Units 1 and 4.

c. The Participants desire to implement the provisions of Section 4 and Section 5 of the Resolution, as soon as possible to allocate the now ongoing costs of the construction and installation of the BART Alternative and other ongoing fuel, capital and restructuring costs, and PNM will file this Funding Agreement with FERC seeking such approval.

d. The Exiting Participants will pay a Demand Charge for the use of new Capital Improvements implemented on Unit 4, facilities common to Units 3 and 4, and facilities common to all units, and will continue to pay all operation and maintenance charges associated with their Participation Shares through the Exit Date.

i. The Demand Charge will be $6,200,000 (“Demand Charge”) and will be paid in equal monthly payments for the period between the Effective Date and the Exit Date. The Demand Charge will be paid regardless of the output of Unit 3 or 4.

ii. The Exiting Participants shall pay the Demand Charge as follows:

(1) M-S-R            71.650%

(2) Anaheim        25.000%

(3) SCPPA             2.800%

(4) Tri-State         0.550%

iii. The Remaining Participants shall be paid the Demand Charge as follows:

(1) PNM             0.000%

(2) TEP             0.000%

(3) Farmington        55.600%

(4) LAC            22.200%

14

(5) UAMPS        22.200%

e. Voting for Capital Budget Items for Unit 4, for facilities common to Units 3 and 4 and for facilities common to all Units, shall be in accordance with Section 6.2 of this Funding Agreement.

15

EX-12.1

Exhibit 12.1
PNM RESOURCES, INC. AND SUBSIDIARIES
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Nine Months Ended			Year Ended December 31,
	September 30, 2014			2013				2012			2011				2010				2009
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	87,280		$	118,880			$	125,379		$	122,998			$	123,633			$	123,833
Amortization of debt premium, discount, and expenses	2,824			3,716				4,023			3,695				4,627				5,430
Interest from discontinued operations (including capitalized interest)	—			—				—			—				—				1,027
Estimated interest factor of lease rental charges	3,753			5,847				5,585			6,665				6,888				7,034
Preferred dividend requirements of subsidiary	590			800				769			864				1,075				759
Total Fixed Charges	$	94,447		$	129,243			$	135,756		$	134,222			$	136,223			$	138,083
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	162,166		$	175,069			$	175,035		$	321,469			$	(63,379	)		$	94,751
(Earnings) loss of equity investee	—			—				—			—				15,223				30,145
Earnings (loss) from continuing operations before income taxes, non-controlling interest, and investee earnings	162,166			175,069				175,035			321,469				(48,156		)		124,896
Fixed charges as above	94,447			129,243				135,756			134,222				136,223				138,083
Interest capitalized	(4,166		)	(5,209		)		(5,432		)	(2,697		)		(3,401		)		(7,743		)
Non-controlling interest in earnings of Valencia	(11,140		)	(14,521		)		(14,050		)	(14,047		)		(13,563		)		(11,890		)
Preferred dividend requirements of subsidiary	(590		)	(800		)		(769		)	(864		)		(1,075		)		(759		)
Earnings Available for Fixed Charges	$	240,717		$	283,782			$	290,540		$	438,083			$	70,028			$	242,587
Ratio of Earnings to Fixed Charges	2.55			2.20			1	2.14			3.26			2	0.51			3	1.76
1  Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2013 includes a pre-tax loss of $12.2 million due to the write-off of regulatory disallowances at PNM. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.29.
2  Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2011 includes pre-tax losses of $21.4 million due to the write-off of regulatory disallowances at PNM and TNMP. If those losses were excluded, the Ratio of Earnings to Fixed Charges would have been 3.42. In addition, 2011 includes a pre-tax gain on the sale of First Choice of $174.9 million. If that gain were also excluded, the Ratio of Earnings to Fixed Charges would have been 1.96.
3 The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $66.2 million for the year ended December 31, 2010. Earnings (loss) from continuing operations before income taxes and non-controlling interest includes a pre-tax loss of $188.2 million due to the impairment of PNMR's investment in an equity investee. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 1.90.

EX-12.2

Exhibit 12.2
PUBLIC SERVICE COMPANY OF NEW MEXICO
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Nine Months Ended			Year Ended December 31,
	September 30, 2014			2013				2012			2011				2010			2009
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	59,789		$	79,769			$	82,864		$	75,217			$	73,423		$	73,104
Amortization of debt premium, discount and expenses	1,466			1,879				1,818			1,325				1,274			1,336
Interest from discontinued operations (including capitalized interest)	—			—				—			—				—			1,027
Estimated interest factor of lease rental charges	2,160			3,732				3,743			4,139				4,103			4,517
Total Fixed Charges	$	63,415		$	85,380			$	88,425		$	80,681			$	78,800		$	79,984
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes and non-controlling interest	$	126,843		$	151,480			$	156,314		$	105,965			$	107,288		$	45,627
Fixed charges as above	63,415			85,380				88,425			80,681				78,800			79,984
Non-controlling interest in earnings of Valencia	(11,140		)	(14,521		)		(14,050		)	(14,047		)		(13,563		)	(11,890		)
Interest capitalized	(3,468		)	(4,420		)		(4,314		)	(1,761		)		(2,811		)	(6,067		)
Earnings Available for Fixed Charges	$	175,650		$	217,919			$	226,375		$	170,838			$	169,714		$	107,654
Ratio of Earnings to Fixed Charges	2.77			2.55			1	2.56			2.12			2	2.15			1.35
1 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2013 includes a pre-tax loss $12.2 million due to the write-off of regulatory disallowances. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.70.
2 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2011 includes a pre-tax loss $17.5 million due to the write-off of regulatory disallowances. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.33.

EX-12.3

Exhibit 12.3
TEXAS-NEW MEXICO POWER COMPANY
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Nine Months Ended			Year Ended December 31,
	September 30, 2014			2013			2012			2011				2010			2009
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	18,127		$	24,481		$	26,233		$	27,914			$	28,632		$	25,609
Amortization of debt premium, discount and expenses	865			1,159			1,493			1,679				2,683			3,355
Estimated interest factor of lease rental charges	931			1,241			956			1,202				1,246			831
Total Fixed Charges	$	19,923		$	26,881		$	28,682		$	30,795			$	32,561		$	29,795
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes	$	45,772		$	46,711		$	42,099		$	36,138			$	26,026		$	20,151
Fixed charges as above	19,923			26,881			28,682			30,795				32,561			29,795
Interest capitalized	(414		)	(361		)	(706		)	(593		)		(158		)	(1,144		)
Earnings Available for Fixed Charges	$	65,281		$	73,231		$	70,075		$	66,340			$	58,429		$	48,802
Ratio of Earnings to Fixed Charges	3.28			2.72			2.44			2.15			1	1.79			1.64
1 Earnings from continuing operations before income taxes for the year ended December 31, 2011 includes a pre-tax loss of $3.9 million due to the write-off of regulatory disallowances. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.28.

EX-31.1

PNM Resources

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.1

CERTIFICATION

I, Patricia K. Collawn, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	October 31, 2014	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			PNM Resources, Inc.

EX-31.2

PNM Resources

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.2

CERTIFICATION

I, Charles N. Eldred, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	October 31, 2014	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer
			PNM Resources, Inc.

EX-31.3

Public Service Company of New Mexico

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.3

CERTIFICATION

I, Patricia K. Collawn, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	October 31, 2014	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			Public Service Company of New Mexico

EX-31.4

Public Service Company of New Mexico

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.4

CERTIFICATION

I, Charles N. Eldred, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	October 31, 2014	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer
			Public Service Company of New Mexico

EX-31.5

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 31.5

CERTIFICATION

I, Patricia K. Collawn, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	October 31, 2014	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chief Executive Officer
			Texas-New Mexico Power Company

EX-31.6

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 31.6

CERTIFICATION

I, Thomas G. Sategna, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	October 31, 2014	By:	/s/ Thomas G. Sategna
			Thomas G. Sategna
			Vice President and Controller
			Texas-New Mexico Power Company

EX-32.1

PNM Resources

414 Silver Ave. SW

Albuquerque, NM 87102-3289

www.pnmresources.com

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2014, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on October 31, 2014 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	October 31, 2014	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			PNM Resources, Inc.
		By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer

EX-32.2

Public Service Company of New Mexico

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2014, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on October 31, 2014 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	October 31, 2014	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			Public Service Company of New Mexico
		By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer

EX-32.3

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 32.3

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2014, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on October 31, 2014 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	October 31, 2014	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chief Executive Officer
			Texas-New Mexico Power Company
		By:	/s/ Thomas G. Sategna
			Thomas G. Sategna
			Vice President and Controller
			Texas-New Mexico Power Company

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Lease Commitments (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014 Public Service Company of New Mexico [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]	Feb. 25, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station, Unit 2 Leases 31.2494 MW [Member]	May 01, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station, Unit 2 Leases [Member] MW	Sep. 30, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station, Unit 2 Leases, January 15, 2016 [Member] MW	May 01, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]	May 01, 2014 Maximum [Member] Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]	May 01, 2014 Minimum [Member] Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]
Operating Leased Assets [Line Items]
Rental Payments, Fixed renewal option period during original terms of leases			50.00%
Purchase Price of Leased Asset to be paid January 15, 2016				$ 78.1			$ 85.2
Leased Capacity to be Purchased					32.76	31.25
Early Purchase Price of Leased Asset effective June 1, 2014							79.9
Additional consideration for early purchase of leased asset effective June 1, 2014								$ 5.8	$ 1.2
Operating Lease, Extended Term	2 years
Operating Leases, Renewal Options After Original Lease Term (in years)	6 years	2 years

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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Service billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 20,813	$ 22,241	$ 64,069	$ 65,729
Service billings [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	6,471	6,731	20,695	20,948
Service billings [Member] | PNM to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	142	140	402	381
Service billings [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	20	2	21	6
Interest charges [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	1	0	55	1
Interest charges [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	65	139	245	354
Interest charges [Member] | PNM to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	28	35	79	113
Income tax sharing payments [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	0	45,000
Income tax sharing payments [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 0	$ 0	$ 0	$ 0

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Financing, Financing Activities (Details) (USD $)					3 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 Public Service Company of New Mexico [Member] PNM 2014 Term Loan Agreement [Member]	Mar. 05, 2014 Public Service Company of New Mexico [Member] PNM 2014 Term Loan Agreement [Member]	Sep. 30, 2014 Texas-New Mexico Power Company [Member] Notes Payable to Banks [Member]	Sep. 30, 2014 Texas-New Mexico Power Company [Member] 2011 Term Loan Agreement, First Mortgage Bonds Due 2014 [Member]	Sep. 30, 2014 Local Lines of Credit [Member] Public Service Company of New Mexico [Member]	Jan. 08, 2014 Local Lines of Credit [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2013 Local Lines of Credit [Member] Public Service Company of New Mexico [Member]	Apr. 22, 2013 PNM Term Loan Agreement [Member] Notes Payable to Banks [Member]	Dec. 09, 2013 First Mortgage Bonds Due 2024, Series 2014A, at 4 point 03 percent [Member] [Member] Texas-New Mexico Power Company [Member] Bonds [Member]
Debt Instrument [Line Items]
Debt Instruments, NMPRC Approved credit facility								$ 50,000,000
Long-term Debt				175,000,000
Short-term debt	100,000,000	149,200,000					0		0	75,000,000
Debt Instrument, Interest Rate at Period End			1.10%
Debt Instrument, Face Amount											80,000,000
Debt Instrument, Interest Rate, Stated Percentage											4.03%
Proceeds from Bank Debt					$ 30,000,000	$ 50,000,000

XML

Goodwill (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Apr. 01, 2014 Public Service Company of New Mexico [Member]	Apr. 01, 2013 Public Service Company of New Mexico [Member]	Apr. 01, 2012 Texas-New Mexico Power Company [Member]
Goodwill [Line Items]
Goodwill	$ 278,297	$ 278,297	$ 278,297	$ 51,600		$ 226,700
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount				30.00%	27.00%	26.00%

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Stock-Based Compensation (Details) (USD $)	9 Months Ended			9 Months Ended					1 Months Ended				9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 Stock Options [Member]	Sep. 30, 2014 Restricted Stock [Member]	Sep. 30, 2013 Restricted Stock [Member]	Sep. 30, 2014 Market-Based Shares [Member]	Sep. 30, 2013 Market-Based Shares [Member]	Feb. 28, 2014 Executive [Member] Performance Shares [Member]	Sep. 30, 2014 Executive [Member] Performance Shares [Member]	Mar. 31, 2012 Chairman, President, and Chief Executive Officer [Member] Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee [Member] Common Stock [Member]	Mar. 31, 2012 Chairman, President, and Chief Executive Officer [Member] Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 and she remains an employee [Member] Common Stock [Member]	Sep. 30, 2014 Performance Equity Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period													3 years
Share-based Compensation Arrangement by Share-based Payment Award, Vesting Rate													100.00%
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 7,900,000		$ 4,600,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options, Outstanding at beginning of period, Shares	1,343,666
Options, Outstanding at beginning of period, Weighted-Average Exercise Price (in dollars per share)	$ 20.63
Options, Granted, Shares	0
Options, Granted, Weighted-Average Exercise Price (in dollars per share)	$ 0.00
Options, Exercised, Shares	(287,075)
Options, Exercised, Weighted-Average Exercise Price (in dollars per share)	$ 19.00
Options, Forfeited, Shares	(38,534)
Options, Forfeited, Weighted-Average Exercise Price (in dollars per share)	$ 27.59
Options, Expired, Shares	(17,151)
Options, Expired, Weighted-Average Exercise Price (in dollars per share)	$ 26.43
Options, Outstanding at end of period, Shares	1,000,906
Options, Outstanding at end of period, Weighted-Average Exercise Price (in dollars per share)	$ 20.73
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Nonvested Restricted Stock, Nonvested at beginning of period, Shares					315,305
Nonvested Restricted Stock, Nonvested at beginning of period, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 17.87
Nonvested Restricted Stock, Granted, Shares					242,164
Nonvested Restricted Stock, Granted, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 21.27	$ 20.03
Nonvested Restricted Stock, Vested, Shares					(295,423)
Nonvested Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 16.68
Nonvested Restricted Stock, Forfeited, Shares					(515)
Nonvested Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 24.74
Nonvested Restricted Stock, Nonvested at end of period, Shares					261,531
Nonvested Restricted Stock, Nonvested at end of period, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 22.31
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options, Outstanding at end of period, Aggregate Intrinsic Value				6,200,000
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years)				2 years 11 months 23 days
Options, Outstanding at end of period, No intrinsic value	435,472
Weighted-average grant date fair value options granted (dollars per share)	$ 0.00	$ 0.00
Total fair value of options that vested	0	625,000
Total intrinsic value of options exercised	2,199,000	2,466,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Total fair value of shares that vested					$ 4,929,000	$ 4,395,000
Expected quarterly dividends per share					$ 0.185	$ 0.165
Risk-free interest rate					0.62%	0.34%	0.64%	0.36%
Granted and Vested in Period									112,864
Share based Compensation, weighted percentage assigned to achieving market targets									60.00%
Share based Compensation, weighted percentage assigned to achieving performance targets									40.00%
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year One										198,369
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Two										179,811
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Three										175,735
Shares received if achieves specified improvement in total shareholders return											135,000	35,000
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate							2.82%	2.86%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate							25.11%	25.11%

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(In thousands)
Services billings:
PNMR to PNM	$	20,813	$	22,241	$	64,069	$	65,729
PNMR to TNMP	6,471		6,731		20,695		20,948
PNM to TNMP	142		140		402		381
TNMP to PNMR	20		2		21		6
Interest billings:
PNMR to TNMP	65		139		245		354
PNMR to PNM	1		—		55		1
PNM to PNMR	28		35		79		113
Income tax sharing payments:
PNMR to PNM	—		—		—		45,000
PNMR to TNMP	—		—		—		—

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	55,653	$	54,555	$	97,262	$	92,859
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	112		177		134		194
Average Shares – Basic	79,766		79,831		79,788		79,848
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	457		503		491		608
Average Shares – Diluted	80,223		80,334		80,279		80,456
Net Earnings Per Share of Common Stock:
Basic	$	0.70	$	0.68	$	1.22	$	1.16
Diluted	$	0.69	$	0.68	$	1.21	$	1.15

⁽¹⁾  Excludes the effect of out-of-the-money options for 435,472 shares of common stock at September 30, 2014.

XML

Commitments and Contingencies (Commitments and Contingencies Related to the Environment) (Details) (USD $)											9 Months Ended			0 Months Ended																			0 Months Ended							12 Months Ended				3 Months Ended			0 Months Ended
	Dec. 21, 2011 mw	Sep. 30, 2014 Clean Air Act related to Regional Haze [Member] state	Dec. 21, 2011 San Juan Generating Station [Member]	Nov. 08, 2013 Public Service Company of New Mexico [Member] National Ambient Air Quality Standards [Member] San Juan Generating Station [Member]	Oct. 31, 2012 Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Oct. 31, 2012 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Clean Air Act, SCR [Member] [Member] Minimum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]	Oct. 31, 2012 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Clean Air Act, SCR [Member] [Member] Maximum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]	Dec. 20, 2013 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Clean Air Act, SNCR [Member] MW	Oct. 31, 2012 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Clean Air Act, SNCR [Member] Minimum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]	Oct. 31, 2012 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Clean Air Act, SNCR [Member] Maximum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Mercury Control [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Mercury Control [Member] Maximum [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Units 2 and 3 [Member]	Oct. 01, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Units 2 and 3 [Member] Clean Air Act, SNCR [Member]	Dec. 20, 2013 Public Service Company of New Mexico [Member] San Juan Generating Station Units 2 and 3 [Member] Clean Air Act, SNCR [Member] MW	Oct. 01, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Units 2 and 3 [Member] Clean Air Act, SNCR [Member]	Oct. 01, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Units 2 and 3 [Member] Clean Air Act, SNCR [Member] Subsequent Event [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station Unit 3 [Member]	Oct. 01, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station Unit 3 [Member] Clean Air Act, SNCR [Member] Subsequent Event [Member]	Jun. 26, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Units 1 and 4 [Member]	Dec. 20, 2013 Public Service Company of New Mexico [Member] San Juan Generating Station Units 1 and 4 [Member] Clean Air Act, SNCR [Member] Maximum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]	Oct. 01, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Units 1 and 4 [Member] Clean Air Act, SNCR [Member] Subsequent Event [Member] Maximum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]	Jun. 26, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member] Clean Air Act, SNCR [Member]	Jun. 26, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member] Clean Air Act, SNCR [Member] MW	Dec. 20, 2013 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member] Clean Air Act, SNCR [Member] MW	Jun. 27, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member] Clean Air Act, SNCR [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]	Mar. 11, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member] Clean Air Act, SNCR [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]	Oct. 01, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member] Clean Air Act, SNCR [Member] Subsequent Event [Member] MW	Sep. 30, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 3 [Member] Clean Air Act, SNCR [Member]	Dec. 20, 2013 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 3 [Member] Clean Air Act, SNCR [Member] MW	Oct. 01, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 3 [Member] Clean Air Act, SNCR [Member] Subsequent Event [Member]	Oct. 01, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 3 [Member] Clean Air Act, SNCR [Member] Subsequent Event [Member] Minimum [Member]	Oct. 01, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Unit 3 [Member] Clean Air Act, SNCR [Member] Subsequent Event [Member] Maximum [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Four Corners [Member] Clean Air Act Related to Post Combustion Controls [Member]	Aug. 06, 2012 Public Service Company of New Mexico [Member] Four Corners [Member] Clean Air Act Related to Post Combustion Controls [Member] compliance_alternative	Sep. 30, 2014 Public Service Company of New Mexico [Member] Four Corners Units 4 and 5 (Coal) [Member] Clean Air Act Related to Post Combustion Controls [Member]	Jan. 31, 2010 Public Service Company of New Mexico [Member] San Juan Generating Station And Four Corners [Member] Minimum [Member] opp	Jan. 31, 2010 Public Service Company of New Mexico [Member] San Juan Generating Station And Four Corners [Member] Maximum [Member] opp	Dec. 31, 2013 Public Service Company of New Mexico [Member] Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member] Other Deferred Credits [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member] Other Deferred Credits [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member] Settled Litigation [Member]	Sep. 30, 2014 PNMR and PNM [Member] Palo Verde Nuclear Generating Station Unit 3 [Member] MW	Dec. 20, 2013 PNMR and PNM [Member] Palo Verde Nuclear Generating Station Unit 3 [Member] Clean Air Act, SNCR [Member] MW	Oct. 01, 2014 PNMR and PNM [Member] Palo Verde Nuclear Generating Station Unit 3 [Member] Clean Air Act, SNCR [Member] Subsequent Event [Member]	Oct. 01, 2014 PNMR and PNM [Member] Palo Verde Nuclear Generating Station Unit 3 [Member] Clean Air Act, SNCR [Member] Subsequent Event [Member] MW	Sep. 30, 2014 Pnm Electric [Member] San Juan Generating Station Units 2 and 3 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Lawsuit settlement, third party receipt																																												$ 57,400,000
PNMs share of lawsuit settlement, third party receipt																																												5,900,000
Loss Contingency, Estimate of Possible Loss																																			80,300,000						58,000,000
Loss Contingency Accrual																																										12,200,000	11,900,000
Annual Fee, Nuclear Waste Disposal																																								3,000,000
Revised Annual Fee, Nuclear Waste Disposal																																								0
Public Utilities, Number of States To Address Regional Haze		50
Public Utilities, Potential to emit tons per year of visibility impairing pollution, maximum		250
Estimated Total Capital Cost If Requirement Occurred						824,000,000	910,000,000
Estimated Installation Capital Costs									85,000,000	90,000,000											82,000,000	90,600,000
Estimated Portion of Total Capital Costs if Requirement Occured									105,000,000	110,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share					46.30%
Public Utilities, Requested Time Period to Recover Retired Units NBV														20 years	20 years
Public Utilities, Number of Megawatts Nuclear Generation																																													134	134		134
Public Utilities, Proposed value per Kilowatt effective January 1, 2018																			1,650																											2,500
Public Utilities, Additional Ownership To Be Obtained, in Megawatts																									132	78			132
Public Utilities, Overall Reduction Of Ownership, in Megawatts								340
Public Utilities, Newly Identified Replacement Gas-fired Generation, in Megawatts, December2013															177
Public Utilities, Newly Identified Replacement Solar Generation, in Megawatts, December2013															40
Estimated cost of replacing gas fired peaking capacity due to retirement of SJGS units																																																	268,300,000
Public Utilities, Ownership To Be Exchanged, in Megawatts																															78
Public Utilities, Estimated rate base value at 1/1/2018																			221,100,000										26,000,000
Public Utilities, Proposed reduction in carrying value																																26,000,000
Public Utilities, Recovery Percentage of Estimated undepreciated value at 12/31/17																	50.00%
Public Utilities, Estimated undepreciated value at 12/31/17																	231,000,000
Net book value													284,000,000					143,000,000
Public Utilities, Percentage capacity factor 7-year performance threshold																																																75.00%
Public Utilities, Period over which to measure capacity performance																																															7 years
Public Utilities,Estimated unrecoverable increase in operations and maintenance																																20,000,000
Public Utilities, Write-off Percentage of Estimated undepreciated value at 12/31/17																50.00%
Public Utilities,Estimated pre-tax regulatory disallowance																																	60,000,000	70,000,000
Percentage of ownership held by exiting owners																								38.80%						50.00%
Public Utilities, Ownership Percentage																								38.50%						50.00%							13.00%
Public Utilities, Costs to obtain additional ownership																									0
Jointly Owned Utility Plan, Proposed Proportionate Ownership Share																				59.00%			64.50%
Requested Expenditure, Installation Capital Costs																												1,900,000
Requested Additional Expenditure, Installation Capital Costs																											6,400,000
Public Utilities, Number of Compliance alternatives																																				2
Public Utilities, Plant Requirement to Meet NOx emissions Limit																																			0.015
Public Utilities, Plant Requirement to Meet Opacity Limit, Percentage																																			20.00%
Public Utilities, Rule Imposes Opacity Limitation on Certain Fugitive Dust Emissions From Coal and Material Handling Operations																																			20.00%
Public Utilities, Revised SO2 Emissions Agreed Upon				0.1
Public Utilities, Government Standard Emission Limit																																						0.060	0.070
Current Annual Mercury Control Costs											700,000
Contingent Estimated Annual Mercury Control Cost												$ 6,600,000
Minimum Megawatt Capacity from Coal and Oil-Fired Electric Generating Units under Jurisdiction of the Mercury and Air Toxics Standards	25
Mercury Removal Rate, Percentage			99.00%

XML

Fair Value of Derivative and Other Financial Instruments, Margin, Notional Amounts, Credit Rating (Details) (PNMR and PNM [Member], USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Contractual Liability	$ 1,532	$ 2,398
Existing Cash Collateral	0	0
Net Exposure	$ 1,403	$ 2,152
Gas related contract [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Long Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	656,000	905,000
Power related contract [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Short Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	(2,511,371)	(3,343,783)

XML

Accumulated Other Comprehensive Income (Loss) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Equity [Abstract]
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process			23.60%	19.60%
Percentage of Pension Liability Adjustment Capitalized into Other Accounts			1.70%	1.10%
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			$ (58,140)	$ (81,630)
Amounts reclassified from AOCI (pre-tax)			(7,513)	(4,264)
Income tax impact of amounts reclassified			2,965	1,692
Other OCI changes (pre-tax)			10,049	18,693
Income tax impact of other OCI changes			(3,893)	(7,417)
Net change after income taxes	(644)	5,668	1,608	8,704
Ending Balance	(56,532)	(72,926)	(56,532)	(72,926)
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			25,748	16,406
Amounts reclassified from AOCI (pre-tax)			(11,544)	(9,190)
Income tax impact of amounts reclassified			4,547	3,639
Other OCI changes (pre-tax)			10,202	19,056
Income tax impact of other OCI changes			(3,946)	(7,544)
Net change after income taxes			(741)	5,961
Ending Balance	25,007	22,367	25,007	22,367
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(83,625)	(97,820)
Amounts reclassified from AOCI (pre-tax)			3,864	4,773
Income tax impact of amounts reclassified			(1,524)	(1,893)
Other OCI changes (pre-tax)
Income tax impact of other OCI changes
Net change after income taxes			2,340	2,880
Ending Balance	(81,285)	(94,940)	(81,285)	(94,940)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(263)	(216)
Amounts reclassified from AOCI (pre-tax)			167	153
Income tax impact of amounts reclassified			(58)	(54)
Other OCI changes (pre-tax)			(153)	(363)
Income tax impact of other OCI changes			53	127
Net change after income taxes			9	(137)
Ending Balance	(254)	(353)	(254)	(353)
Public Service Company of New Mexico [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(57,877)	(81,414)
Amounts reclassified from AOCI (pre-tax)			(7,680)	(4,417)
Income tax impact of amounts reclassified			3,023	1,746
Other OCI changes (pre-tax)			10,202	19,056
Income tax impact of other OCI changes			(3,946)	(7,544)
Net change after income taxes			1,599	8,841
Ending Balance	(56,278)	(72,573)	(56,278)	(72,573)
Public Service Company of New Mexico [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			25,748	16,406
Amounts reclassified from AOCI (pre-tax)			(11,544)	(9,190)
Income tax impact of amounts reclassified			4,547	3,639
Other OCI changes (pre-tax)			10,202	19,056
Income tax impact of other OCI changes			(3,946)	(7,544)
Net change after income taxes			(741)	5,961
Ending Balance	25,007	22,367	25,007	22,367
Public Service Company of New Mexico [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(83,625)	(97,820)
Amounts reclassified from AOCI (pre-tax)			3,864	4,773
Income tax impact of amounts reclassified			(1,524)	(1,893)
Other OCI changes (pre-tax)
Income tax impact of other OCI changes
Net change after income taxes			2,340	2,880
Ending Balance	(81,285)	(94,940)	(81,285)	(94,940)
Public Service Company of New Mexico [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance
Amounts reclassified from AOCI (pre-tax)
Income tax impact of amounts reclassified
Other OCI changes (pre-tax)
Income tax impact of other OCI changes
Net change after income taxes
Ending Balance
Texas-New Mexico Power Company [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(263)	(216)
Amounts reclassified from AOCI (pre-tax)			167	153
Income tax impact of amounts reclassified			(58)	(54)
Other OCI changes (pre-tax)			(153)	(363)
Income tax impact of other OCI changes			53	127
Net change after income taxes			9	(137)
Ending Balance	(254)	(353)	(254)	(353)
Texas-New Mexico Power Company [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance
Amounts reclassified from AOCI (pre-tax)
Income tax impact of amounts reclassified
Other OCI changes (pre-tax)
Income tax impact of other OCI changes
Net change after income taxes
Ending Balance
Texas-New Mexico Power Company [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance
Amounts reclassified from AOCI (pre-tax)
Income tax impact of amounts reclassified
Other OCI changes (pre-tax)
Income tax impact of other OCI changes
Net change after income taxes
Ending Balance
Texas-New Mexico Power Company [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(263)	(216)
Amounts reclassified from AOCI (pre-tax)			167	153
Income tax impact of amounts reclassified			(58)	(54)
Other OCI changes (pre-tax)			(153)	(363)
Income tax impact of other OCI changes			53	127
Net change after income taxes			9	(137)
Ending Balance	$ (254)	$ (353)	$ (254)	$ (353)

XML

Regulatory and Rate Matters (Details) (USD $)										3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended		0 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	1 Months Ended	3 Months Ended		0 Months Ended			6 Months Ended	12 Months Ended		0 Months Ended	1 Months Ended				0 Months Ended		1 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Maximum [Member]	Sep. 30, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Maximum [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Wind Energy [Member] Minimum [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Solar Energy [Member] Minimum [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Renewable Technologies [Member] Minimum [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Distributed Generation [Member] Minimum [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2011 [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2015 [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2020 [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] 2014 Wind generated Renewable Energy Credits [Member] MWh	Sep. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard 2014 [Member] MW	Sep. 30, 2014 Public Service Company of New Mexico [Member] 2015 Wind generated Renewable Energy Credits [Member] MWh	Sep. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard 2015 [Member] MW	Sep. 30, 2014 Public Service Company of New Mexico [Member] Renewable Energy Rider [Member] Maximum [Member]	Oct. 05, 2012 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Disincentives / Incentives Adder [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Disincentives / Incentives Adder [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] FPPAC Continuation Application [Member]	Jul. 31, 2011 Public Service Company of New Mexico [Member] Integrated Resource Plan, 2011 [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Integrated Resource Plan, 2011 [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] La Luz Generating Station [Member] MW	May 02, 2014 Public Service Company of New Mexico [Member] Formula Transmission Rate Case [Member]	Jun. 03, 2013 Public Service Company of New Mexico [Member] Formula Transmission Rate Case [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Formula Transmission Rate Case [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] City of Gallup, New Mexico Contract [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] City of Gallup, New Mexico Contract [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Delta [Member] Applications for Approvals to Purchase Delta [Member] MW	Oct. 06, 2014 Public Service Company of New Mexico [Member] Subsequent Event [Member] 2010 Energy Efficiency Application [Member] Disincentives / Incentives Adder [Member]	Jul. 30, 2011 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	Sep. 30, 2014 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] customer	Sep. 30, 2014 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] Minimum [Member]	Sep. 30, 2014 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] Maximum [Member]	Aug. 28, 2012 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Sep. 30, 2014 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Jan. 31, 2013 Texas-New Mexico Power Company [Member] Transmission Rate Filings [Member]	Sep. 30, 2014 Texas-New Mexico Power Company [Member] August 2013 Transmission Rate Filings [Member]	Sep. 30, 2014 Texas-New Mexico Power Company [Member] January 2014 Transmission Rate Filings [Member]	Sep. 30, 2014 Texas-New Mexico Power Company [Member] July 2014 Transmission Rate Filings [Member]
Rate Matters [Line Items]
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales							10.00%	15.00%	20.00%
Public Utilities, Required Percentage of Diversification			30.00%	20.00%	5.00%	1.50%
Public Utilities, Reasonable Cost Threshold	3.00%	3.00%
Public Utilities, Number of Mega Watt Hours of Wind Generation										50,000		120,000
Public Utilities, Number of Mega Watts of Solar PV Capacity											23		40
Public Utilities, Estimated Cost of Mega Watts of Solar PV Capacity											$ 46,700,000		$ 79,300,000
Public Utilities, Wind Capacity Planned Purchase Agreement Term											20 years
Public Utilities, Number of Mega Watts of Wind Energy Capacity											102
Public Utilities, First Year Cost of Wind Capacity Planned Purchase Agreement											5,800,000.0
Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013														10.50%
Public Utilities, Annual Revenue To be Collected Under Current Rider Rate														34,600,000
Public Utilities, Annual Revenue To be Collected Under 2015 Rider Rate														44,700,000
Public Utilities, Program Costs Related To Energy Efficiency															22,500,000														25,800,000
Public Utilities, Approved Profit Incentive Adder Revenues Related To Energy Efficiency Program, Percentage of Program Costs																7.60%
Public Utilities, Approved Profit Incentive Adder Revenues Related To Energy Efficiency Program																1,700,000
Public Utilities, Proposed Profit Incentive Adder Revenues Related To 2015 Energy Efficiency Program																													2,100,000
Public Utilities, Retention Percentage of Sales Margins																	10.00%	10.00%
Public Utilities, Under-collected balance write-off																			10,500,000
Public Utilities, Period over which to write off remaining uncollected balance																			18 months
Public Utilities, Frequency of IRP filings																					3 years
Public Utilities, Planning Period Covered of IRP																				20 years
Public Utilities, Number of Mega Watts Natural Gas Peaking Units to be Purchased																												132
Public Utilities, Number of Mega Watts of Gas-fired Generation																						40
Public Utilities, Rate Base Value																						56,000,000
Amount of Regulatory Costs Not yet Approved																									3,200,000
Public Utilities, Return on Equity																									10.81%
Percentage ownership of EIP transmission line																									60.00%
Public Utilities, Requested Rate Increase (Decrease), Amount																							500,000	1,300,000
Public Utilities, Revenue For Power Sold Under Specific Contract																										6,100,000	11,700,000
Public Utilities, Approved Deployment Costs																														113,300,000
Public Utilities, Collection of Deployment Costs Through Surcharge Period																														12 years
Public Utilities, Completion Period of Advanced Meter Deployment																														5 years
Public Utilities, Non-standard metering service cost total to be borne by opt-out customers																															200,000
Public Utilities, Non-standard metering service cost initial fee range																																142.84	247.48
Public Utilities, Non-standard metering ongoing expenses total to be borne by opt-out customers																															500,000
Public Utilities, Non-standard metering ongoing expenses monthly charge																															38.99
Public Utilities, Approved Non-standard metering service cost initial fee range																																63.97	168.61
Public Utilities, Approved Non-standard metering ongoing expenses monthly charge																															36.78
Presumed number of customers that will elect non-standard meter service																															1,081
Current number of customers that have elected non-standard meter service																															59
Public Utilities, Approved Program Implementation Costs, Bonus																																		5,200,000
Public Utilities, Unapproved 2014 Program Implementation Costs																																			5,600,000
Public Utilities, Unapproved 2015 Program Implementation Costs																																			5,700,000
Public Utilities, Approved 2014 Incentive Portion of Program Implementation Costs																																			1,500,000
Public Utilities, Approved 2015 Program Implementation Costs																																			5,700,000
Public Utilities, Additional Revenue from Proposed Rates																																				21,900,000	18,100,000	18,200,000	25,200,000
Public Utilities, Total Revenue Requirement Increase																																				$ 2,900,000	$ 2,800,000	$ 2,900,000	$ 4,200,000

XML

Financing, Short-term Debt (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Oct. 24, 2014 Subsequent Event [Member]	Sep. 30, 2014 PNMR Term Loan Agreement [Member]	Dec. 31, 2013 PNMR Term Loan Agreement [Member]	Oct. 24, 2014 PNM Resources [Member] Subsequent Event [Member]	Oct. 24, 2014 Public Service Company of New Mexico [Member] Subsequent Event [Member]	Oct. 24, 2014 Public Service Company of New Mexico [Member] Subsequent Event [Member] Affiliated Entity [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Local Lines of Credit [Member]	Jan. 08, 2014 Public Service Company of New Mexico [Member] Local Lines of Credit [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Local Lines of Credit [Member]	Oct. 24, 2014 Public Service Company of New Mexico [Member] Local Lines of Credit [Member] Subsequent Event [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Intercompany loan agreements [Member]	Oct. 24, 2014 Texas-New Mexico Power Company [Member] Subsequent Event [Member]	Oct. 24, 2014 Texas-New Mexico Power Company [Member] Subsequent Event [Member] Affiliated Entity [Member]	Sep. 30, 2014 Texas-New Mexico Power Company [Member] Intercompany loan agreements [Member]	Sep. 30, 2014 Line of Credit [Member]	Dec. 31, 2013 Line of Credit [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] PNM Resources [Member]	Dec. 31, 2013 Revolving Credit Facility [Member] PNM Resources [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2013 Revolving Credit Facility [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Texas-New Mexico Power Company [Member]	Dec. 31, 2013 Revolving Credit Facility [Member] Texas-New Mexico Power Company [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Texas-New Mexico Power Company [Member] First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity																			$ 300,000,000.0		$ 400,000,000.0		$ 75,000,000.0
Debt Instrument, Collateral Amount																									75,000,000
Debt Instruments, NMPRC Approved credit facility										50,000,000
Short-term debt - affiliate													6,500,000			19,100,000
Short-term Debt, Weighted Average Interest Rate				1.01%
Short-term debt	100,000,000	149,200,000		100,000,000	100,000,000				0		0						100,000,000	149,200,000	0	0	0	49,200,000	0	0
Line of Credit Facility, Remaining Borrowing Capacity			814,000,000			292,300,000	396,800,000					50,000,000		74,900,000
Short-term debt – affiliate								7,400,000							25,700,000
Restricted Cash and Investments						$ 23,100,000	$ 0							$ 0

XML

Significant Accounting Policies and Responsibility for Financial Statements

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Significant Accounting Policies and Responsibility for Financial Statements

Significant Accounting Policies and Responsibility for Financial Statements

Financial Statement Preparation

In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at September 30, 2014 and December 31, 2013, the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the consolidated cash flows for the nine months ended September 30, 2014 and 2013. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.

The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are so indicated. Certain amounts in the 2013 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2014 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s, and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2013 Annual Reports on Form 10-K.

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

Principles of Consolidation

The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM began consolidating Rio Bravo, formerly known as Delta, upon its acquisition on July 17, 2014. PNM also consolidates the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 14.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.185 per share in July 2014 and $0.165 in July 2013, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. The Board declared dividends on common stock considered to be for the third quarter of $0.185 per share in September 2014 and $0.165 in September 2013, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

PNM declared and paid cash dividends on its common stock to PNMR of $30.3 million and $68.0 million in the nine months ended September 30, 2014 and 2013. TNMP declared and paid cash dividends of $16.3 million and $3.7 million in the nine months ended September 30, 2014 and 2013.

New Accounting Pronouncements

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

Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606)

On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for the Company beginning on January 1, 2017. Early adoption is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

Accounting Standards Update 2014-12 – Compensation-Stock Compensation (Topic 718) Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period

On June 19, 2014, the FASB issued ASU No. 2014-12, which requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in estimating the grant date fair value of the award. The new standard is effective for the Company beginning on January 1, 2016. Early adoption is permitted and the standard permits the use of either the prospective or retrospective transition methods. Although the Company is in the process of analyzing the impacts this new standard will have on its consolidated financial statements, the Company currently treats the performance targets covered by the standard as performance conditions, so the Company does not expect its impact will be significant.

Accounting Standards Update 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

On August 27, 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company is in the process of analyzing the impacts of this new standard .

XML

Fair Value of Derivative and Other Financial Instruments, Available for Sale Securities (Details) (PNMR and PNM [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	$ 235,894		$ 235,894		$ 226,855
Available-for-sale securities, Unrealized gains			41,272		42,602
Proceeds from sales	29,103	103,230	82,222	179,336
Gross realized gains	3,134	2,719	11,616	8,962
Gross realized (losses)	(2,172)	(531)	(3,382)	(2,027)
Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	3,338		3,338		3,356
Available-for-sale securities, Unrealized gains			0		0
Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	41,917		41,917		39,460
Available-for-sale securities, Unrealized gains			15,360		14,523
Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	74,647		74,647		76,292
Available-for-sale securities, Unrealized gains			18,452		25,656
International and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	16,957		16,957		16,633
Available-for-sale securities, Unrealized gains			1,339		1,040
U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	19,616		19,616		21,941
Available-for-sale securities, Unrealized gains			520		158
Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	67,595		67,595		58,568
Available-for-sale securities, Unrealized gains			4,970		1,018
Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	11,824		11,824		10,605
Available-for-sale securities, Unrealized gains			631		207
Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	235,894		235,894		226,855
Fair Value, Measurements, Recurring [Member] | Nuclear Decommissioning Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	231,400		231,400		222,500
Fair Value, Measurements, Recurring [Member] | Mine Reclamation Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	4,500		4,500		4,400
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	3,338		3,338		3,356
Fair Value, Measurements, Recurring [Member] | Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	41,917		41,917		39,460
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	74,647		74,647		76,292
Fair Value, Measurements, Recurring [Member] | International and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	16,957		16,957		16,633
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	19,616		19,616		21,941
Fair Value, Measurements, Recurring [Member] | Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	67,595		67,595		58,568
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	$ 11,824		$ 11,824		$ 10,605

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Fair Value of Derivative and Other Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2014

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

Fair Value, by Balance Sheet Grouping

The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:

					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
September 30, 2014	(In thousands)
PNMR
Long-term debt	$	1,875,172	$	2,072,872	$	—	$	2,072,872	$	—
Investment in PVNGS lessor notes	$	31,469	$	32,712	$	—	$	—	$	32,712
Other investments	$	1,667	$	2,406	$	546	$	—	$	1,860
PNM
Long-term debt	$	1,390,647	$	1,525,625	$	—	$	1,525,625	$	—
Investment in PVNGS lessor notes	$	31,469	$	32,712	$	—	$	—	$	32,712
Other investments	$	300	$	300	$	300	$	—	$	—
TNMP
Long-term debt	$	365,759	$	422,583	$	—	$	422,583	$	—
Other investments	$	245	$	245	$	245	$	—	$	—
December 31, 2013
PNMR
Long-term debt	$	1,745,420	$	1,905,230	$	—	$	1,905,230	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279
Other investments	$	1,835	$	3,196	$	690	$	—	$	2,506
PNM
Long-term debt	$	1,290,618	$	1,382,938	$	—	$	1,382,938	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279
Other investments	$	445	$	445	$	445	$	—	$	—
TNMP
Long-term debt	$	336,036	$	390,814	$	—	$	390,814	$	—
Other investments	$	245	$	245	$	245	$	—	$	—

The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the nine months ended September 30, 2014 and the year ended December 31, 2013.

PNMR and PNM [Member]

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

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows:

	Economic Hedges
	September 30, 2014			December 31, 2013
PNMR and PNM	(In thousands)
Current assets	$	4,148		$	4,064
Deferred charges	1,084			3,002
	5,232			7,066
Current liabilities	(1,370		)	(2,699		)
Long-term liabilities	(688		)	(1,094		)
	(2,058		)	(3,793		)
Net	$	3,174		$	3,273

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.

	Economic Hedges
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
PNMR and PNM	(In thousands)
Electric operating revenues	$	2,352		$	7,077		$	(2,124	)	$	5,743
Cost of energy	(60		)	(72		)	186			421
Total gain (loss)	$	2,292		$	7,005		$	(1,938	)	$	6,164

Schedule of Notional Amounts of Outstanding Derivative Positions

Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:

	Economic Hedges
	MMBTU	MWh
September 30, 2014
PNMR and PNM	656,000	(2,511,371	)
December 31, 2013
PNMR and PNM	905,000	(3,343,783	)

Schedule of Collateral Related to Derivative

Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions.

Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
September 30, 2014
PNMR and PNM	$	1,532	$	—	$	1,403
December 31, 2013
PNMR and PNM	$	2,398	$	—	$	2,152

Available-for-sale Securities

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold and reflect impairments.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(In thousands)
Proceeds from sales	$	29,103		$	103,230		$	82,222		$	179,336
Gross realized gains	$	3,134		$	2,719		$	11,616		$	8,962
Gross realized (losses)	$	(2,172	)	$	(531	)	$	(3,382	)	$	(2,027	)

The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table. At September 30, 2014 and December 31, 2013, the fair value of available-for-sale securities included $231.4 million and $222.5 million for the NDT and $4.5 million and $4.4 million for the mine reclamation trust.

	September 30, 2014				December 31, 2013
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,338	$	—	$	3,356
Equity securities:
Domestic value	15,360		41,917		14,523		39,460
Domestic growth	18,452		74,647		25,656		76,292
International and other	1,339		16,957		1,040		16,633
Fixed income securities:
U.S. Government	520		19,616		158		21,941
Municipals	4,970		67,595		1,018		58,568
Corporate and other	631		11,824		207		10,605
	$	41,272	$	235,894	$	42,602	$	226,855

Investments Classified by Contractual Maturity Date

At September 30, 2014, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR		PNM
	(In thousands)
Within 1 year	$	3,601	$	7,994	$	7,994
After 1 year through 5 years	20,886		25,456		24,718
After 5 years through 10 years	11,561		—		—
After 10 years through 15 years	9,549		—		—
After 15 years through 20 years	11,313		—		—
After 20 years	42,125		—		—
	$	99,035	$	33,450	$	32,712

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at September 30, 2014 and December 31, 2013 for items recorded at fair value.

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2014	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,338		$	3,338	$	—
Equity securities:
Domestic value	41,917			41,917		—
Domestic growth	74,647			74,647		—
International and other	16,957			16,957		—
Fixed income securities:
U.S. Government	19,616			17,865		1,751
Municipals	67,595			—		67,595
Corporate and other	11,824			2,544		9,280
	$	235,894		$	157,268	$	78,626
Commodity derivative assets	$	5,232		$	—	$	5,232
Commodity derivative liabilities	(2,058		)	—		(2,058		)
Net	$	3,174		$	—	$	3,174
December 31, 2013
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,356		$	3,356	$	—
Equity securities:
Domestic value	39,460			39,460		—
Domestic growth	76,292			76,292		—
International and other	16,633			16,633		—
Fixed income securities:
U.S. Government	21,941			20,194		1,747
Municipals	58,568			—		58,568
Corporate and other	10,605			2,245		8,360
	$	226,855		$	158,180	$	68,675
Commodity derivative assets	$	7,066		$	—	$	7,066
Commodity derivative liabilities	(3,793		)	—		(3,793		)
Net	$	3,273		$	—	$	3,273

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

9 Months Ended

Sep. 30, 2014

Public Service Company of New Mexico [Member]

Variable Interest Entity [Line Items]

Noncontrolling Interest Summarized Financial Information

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Operating revenues	$	5,061		$	5,453		$	15,300		$	15,150
Operating expenses	(1,360		)	(1,326		)	(4,160		)	(4,246		)
Earnings attributable to non-controlling interest	$	3,701		$	4,127		$	11,140		$	10,904

Financial Position

	September 30,		December 31,
	2014		2013
	(In thousands)
Current assets	$	3,435	$	2,658
Net property, plant, and equipment	73,024		75,137
Total assets	76,459		77,795
Current liabilities	1,039		766
Owners’ equity – non-controlling interest	$	75,420	$	77,029

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Fair Value of Derivative and Other Financial Instruments, Debt Maturities (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014
PNMR and PNM [Member]
Available-for-sale Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Available-for-sale debt securities, Within 1 year	$ 3,601
Available-for-sale debt securities, After 1 year through 5 years	20,886
Available-for-sale debt securities, After 5 years through 10 years	11,561
Available-for-sale debt securities, After 10 years through 15 years	9,549
Available-for-sale debt securities, After 15 years through 20 years	11,313
Available-for-sale debt securities, After 20 years	42,125
Available-for-sale debt securities	99,035
PNM Resources [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Held-to-maturity debt securities, Due within 1 year	7,994
Held-to-maturity debt securities, After 1 year through 5 years	25,456
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	33,450
Public Service Company of New Mexico [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Held-to-maturity debt securities, Due within 1 year	7,994
Held-to-maturity debt securities, After 1 year through 5 years	24,718
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	$ 32,712

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2014

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

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:

	Nine Months Ended September 30,
Restricted Shares and Performance Based Shares	2014			2013
Expected quarterly dividends per share	$	0.185		$	0.165
Risk-free interest rate	0.62		%	0.34		%
Market-Based Shares
Dividend yield	2.82		%	2.86		%
Expected volatility	25.11		%	25.11		%
Risk-free interest rate	0.64		%	0.36		%

The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the nine months endedSeptember 30, 2014:

	Stock Option Shares		Weighted- Average Exercise Price		Restricted Stock		Weighted- Average Grant Date Fair Value
Outstanding at beginning of period	1,343,666		$	20.63	315,305		$	17.87
Granted	—		$	—	242,164		$	21.27
Exercised	(287,075	)	$	19.00	(295,423	)	$	16.68
Forfeited	(38,534	)	$	27.59	(515	)	$	24.74
Expired	(17,151	)	$	26.43	—		$	—
Outstanding at end of period	1,000,906		$	20.73	261,531		$	22.31

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

	Nine Months Ended September 30,
Stock Options	2014		2013
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	625
Total intrinsic value of options exercised (in thousands)	$	2,199	$	2,466
Restricted Stock
Weighted-average grant date fair value	$	21.27	$	20.03
Total fair value of restricted shares that vested (in thousands)	$	4,929	$	4,395

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Financing (Tables)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Schedule of Short-term Debt

Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2014		2013
	(In thousands)
PNM:
Revolving credit facility	$	—	$	49,200
PNM New Mexico Credit Facility	—		—
TNMP – Revolving credit facility	—		—
PNMR:
Revolving credit facility	—		—
PNMR Term Loan Agreement	100,000		100,000
	$	100,000	$	149,200

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Condensed Consolidated Statements of Changes in Equity (USD $) In Thousands, unless otherwise specified	Total	Common Stock [Member]	AOCI [Member]	Retained Earnings [Member]	Parent [Member]	Non-controlling Interest in Valencia [Member]	Pnm Electric [Member]	Pnm Electric [Member] Common Stock [Member]	Pnm Electric [Member] AOCI [Member]	Pnm Electric [Member] Retained Earnings [Member]	Pnm Electric [Member] Parent [Member]	Pnm Electric [Member] Non-controlling Interest in Valencia [Member]	Tnmp Electric [Member]	Tnmp Electric [Member] Common Stock [Member]	Tnmp Electric [Member] Additional Paid-in Capital [Member]	Tnmp Electric [Member] AOCI [Member]	Tnmp Electric [Member] Retained Earnings [Member]
Balance TNMP at Dec. 31, 2013	$ 1,673,569						$ 1,210,199						$ 502,931	$ 64	$ 404,166	$ (263)	$ 98,964
Balance at Dec. 31, 2013	1,750,598	1,178,369	(58,140)	553,340	1,673,569	77,029	1,287,228	1,061,776	(57,877)	206,300	1,210,199	77,029
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from stock option exercise	5,495	5,495			5,495
Awards of common stock	(15,573)	(15,573)			(15,573)
Excess tax (shortfall) from stock-based payment arrangements	(95)	(95)			(95)
Stock based compensation expense	4,680	4,680			4,680
Valencia’s transactions with its owner	(12,749)					(12,749)	(12,749)	0	0	0	0	(12,749)
Net Earnings	108,798			97,658	97,658	11,140	84,512	0	0	73,372	73,372	11,140	28,691
Net earnings	97,262						73,372						28,691				28,691
Subsidiary preferred stock dividends	(396)			(396)	(396)
Total other comprehensive income	1,608		1,608		1,608		1,599	0	1,599	0	1,599	0	9			9
Dividends declared on preferred stock	(396)						(396)	0	0	(396)	(396)	0	0
Dividends declared on common stock	(44,208)			(44,208)	(44,208)		(30,263)	0	0	(30,263)	(30,263)	0	(16,336)				(16,336)
Balance TNMP at Sep. 30, 2014	1,722,738						1,254,511						515,295	64	404,166	(254)	111,319
Balance at Sep. 30, 2014	1,798,158	1,172,876	(56,532)	606,394	1,722,738	75,420	1,329,931	1,061,776	(56,278)	249,013	1,254,511	75,420
Balance TNMP at Jun. 30, 2014
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Earnings	59,486						49,052						12,355
Net earnings	55,653						45,351						12,355
Subsidiary preferred stock dividends	(132)
Total other comprehensive income	(644)						(638)						(6)
Dividends declared on preferred stock	(132)						(132)						0
Balance TNMP at Sep. 30, 2014	1,722,738						1,254,511						515,295	64	404,166
Balance at Sep. 30, 2014	$ 1,798,158						$ 1,329,931

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Pension and Other Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2014

Public Service Company of New Mexico [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs

The following tables present the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	45		$	65		$	—	$	—
Interest cost	7,541			7,035			1,159			1,029			205		180
Expected return on plan assets	(9,511		)	(10,482		)	(1,410		)	(1,261		)	—		—
Amortization of net (gain) loss	3,255			3,710			556			1,061			52		58
Amortization of prior service cost	(241		)	19			(336		)	(336		)	—		—
Net periodic benefit cost	$	1,044		$	282		$	14		$	558		$	257	$	238
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	136		$	195		$	—	$	—
Interest cost	22,622			21,106			3,473			3,085			616		540
Expected return on plan assets	(28,533		)	(31,447		)	(4,229		)	(3,782		)	—		—
Amortization of net (gain) loss	9,765			11,130			1,669			3,182			157		174
Amortization of prior service cost	(724		)	57			(1,008		)	(1,008		)	—		—
Net periodic benefit cost	$	3,130		$	846		$	41		$	1,672		$	773	$	714

Texas-New Mexico Power Company [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs

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

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	59		$	75		$	—	$	—
Interest cost	798			772			155			141			10		9
Expected return on plan assets	(1,132		)	(1,212		)	(133		)	(126		)	—		—
Amortization of net (gain) loss	166			262			(31		)	—			—		—
Amortization of prior service cost	—			—			8			14			—		—
Net Periodic Benefit Cost (Income)	$	(168	)	$	(178	)	$	58		$	104		$	10	$	9
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	178		$	225		$	—	$	—
Interest cost	2,395			2,315			464			424			29		27
Expected return on plan assets	(3,395		)	(3,637		)	(400		)	(377		)	—		—
Amortization of net (gain) loss	499			787			(92		)	—			—		—
Amortization of prior service cost	—			—			24			43			—		—
Net Periodic Benefit Cost (Income)	$	(501	)	$	(535	)	$	174		$	315		$	29	$	27

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Fair Value of Derivative and Other Financial Instruments, Derivative Balance Sheet Information (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Current assets	$ 4,148,000	$ 4,064,000
Deferred charges	1,084,000	3,002,000
Commodity derivative instruments, Current liabilities	(1,370,000)	(2,699,000)
Commodity derivative instruments, Long-term liabilities	(688,000)	(1,094,000)
Assets, Current	466,326,000	401,539,000
Liabilities, Current	700,292,000	492,671,000
PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Collateral Already Posted, Aggregate Fair Value	0	0
Derivative, Collateral, Right to Reclaim Cash	0
Margin Deposit Assets	2,400,000	2,800,000
Derivative, Collateral, Obligation to Return Cash	200,000	200,000
Fair Value Hedging [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Current assets	4,148,000	4,064,000
Deferred charges	1,084,000	3,002,000
Commodity derivative instruments, Assets	5,232,000	7,066,000
Commodity derivative instruments, Current liabilities	(1,370,000)	(2,699,000)
Commodity derivative instruments, Long-term liabilities	(688,000)	(1,094,000)
Commodity derivative instruments, Liabilities	(2,058,000)	(3,793,000)
Commodity derivative instruments, Net	3,174,000	3,273,000
Fuel and Purchased Power Adjustment Clause [Member] | Fair Value Hedging [Member] | Commodity Contract [Member] | Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Assets, Current	200,000	400,000
Liabilities, Current	100,000	100,000
Palo Verde Nuclear Generating Station [Member] | Firm Contract [Member] | Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Percentage of Electric Power Plant Output Sold through 2013	100.00%
Palo Verde Nuclear Generating Station [Member] | Fair Value Hedging [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Current assets	3,000,000	3,000,000
Deferred charges	$ 800,000	$ 3,000,000
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation	134
Palo Verde Nuclear Generating Station Unit 3 [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Derivative, Average Forward Price		37

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Income Taxes (Details) (USD $)	3 Months Ended			9 Months Ended
	Sep. 30, 2014	Mar. 31, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Mar. 31, 2013
Income Tax Contingency [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, State and Local, Decrease							$ 1,500,000
New Mexico Corporate tax rate, current	7.60%			7.60%
New Mexico Corporate tax rate, 2014	5.90%			5.90%
Increase in regulatory liabilities due to change in state corporate tax rate	23,900,000
Increase in income tax expense due to change in state corporate tax rate			1,200,000
Decrease in regulatory liabilities due to change in state corporate tax rate		4,600,000
Decrease in deferred tax asset due to change in state corporate tax rate		200,000
Additional Income Tax Expense, Impairment of NM Wind Credits			2,400,000
New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset						19,900,000
Income Tax Expense (Benefit)	(31,055,000)		(30,296,000)	(53,368,000)	(58,600,000)
Liability for Uncertain Tax Positions, Noncurrent	14,300,000			14,300,000
Tax Years 2003 and 2005 - 2008 [Member]
Income Tax Contingency [Line Items]
Income Tax Expense (Benefit)	1,300,000
Public Service Company of New Mexico [Member]
Income Tax Contingency [Line Items]
New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset						11,200,000
Liability for Uncertain Tax Positions, Noncurrent	11,500,000			11,500,000
Public Service Company of New Mexico [Member] | Tax Years 2003 and 2005 - 2008 [Member]
Income Tax Contingency [Line Items]
Income Tax Expense (Benefit)	(1,100,000)
Texas-New Mexico Power Company [Member]
Income Tax Contingency [Line Items]
New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset						6,800,000
Liability for Uncertain Tax Positions, Noncurrent	0			0
Texas-New Mexico Power Company [Member] | Tax Years 2003 and 2005 - 2008 [Member]
Income Tax Contingency [Line Items]
Income Tax Expense (Benefit)	0
PNM Resources [Member] | Tax Years 2003 and 2005 - 2008 [Member]
Income Tax Contingency [Line Items]
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	2,000,000			2,000,000
Income Tax Expense (Benefit)	$ 200,000

XML

Condensed Consolidated Statements of Earnings (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Electric Operating Revenues	$ 413,951	$ 399,730	$ 1,089,008	$ 1,064,993
Operating Expenses:
Cost of energy	132,499	114,674	354,532	325,039
Administrative and general	42,190	46,915	131,283	134,744
Energy production costs	43,287	41,142	136,422	131,546
Regulatory disallowances	0	1,735	0	1,735
Depreciation and amortization	44,295	42,743	128,424	125,189
Transmission and distribution costs	16,884	17,248	49,857	50,690
Taxes other than income taxes	17,997	17,534	51,641	49,739
Total operating expenses	297,152	281,991	852,159	818,682
Operating income	116,799	117,739	236,849	246,311
Other Income and Deductions:
Interest income	2,084	2,264	6,241	7,731
Gains on available-for-sale securities	962	2,188	8,234	6,935
Other income	2,895	3,254	7,648	7,577
Other (deductions)	(2,084)	(5,970)	(7,185)	(13,516)
Net other income and deductions	3,857	1,736	14,938	8,727
Interest Charges	30,115	30,365	89,621	92,279
Earnings before Income Taxes	90,541	89,110	162,166	162,759
Income Taxes	31,055	30,296	53,368	58,600
Net Earnings	59,486	58,814	108,798	104,159
(Earnings) Attributable to Valencia Non-controlling Interest	(3,701)	(4,127)	(11,140)	(10,904)
Preferred Stock Dividend Requirements	(132)	(132)	(396)	(396)
Net Earnings Attributable to PNMR	55,653	54,555	97,262	92,859
Net Earnings Available for PNM Common Stock	55,653	54,555	97,262	92,859
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)	$ 0.70	$ 0.68	$ 1.22	$ 1.16
Diluted (dollars per share)	$ 0.69	$ 0.68	$ 1.21	$ 1.15
Dividends Declared per Common Share (dollars per share)	$ 0.185	$ 0.165	$ 0.555	$ 0.495
Tnmp Electric [Member]
Electric Operating Revenues	78,958	73,704	215,574	201,384
Operating Expenses:
Cost of energy	17,402	14,474	50,167	41,324
Administrative and general	9,230	10,641	27,839	32,446
Depreciation and amortization	13,432	13,850	37,276	37,810
Transmission and distribution costs	6,191	5,562	17,655	17,270
Taxes other than income taxes	6,830	6,923	18,238	17,558
Total operating expenses	53,085	51,450	151,175	146,408
Operating income	25,873	22,254	64,399	54,976
Other Income and Deductions:
Interest income	0	0	0	0
Other income	1,072	820	2,078	1,765
Other (deductions)	(279)	(104)	(583)	(356)
Net other income and deductions	793	716	1,495	1,409
Interest Charges	6,870	6,655	20,122	20,661
Earnings before Income Taxes	19,796	16,315	45,772	35,724
Income Taxes	7,441	6,209	17,081	13,554
Net Earnings	12,355	10,106	28,691	22,170
(Earnings) Attributable to Valencia Non-controlling Interest	0	0	0	0
Preferred Stock Dividend Requirements	0	0	0	0
Net Earnings Attributable to PNMR	12,355	10,106	28,691	22,170
Net Earnings Available for PNM Common Stock	12,355	10,106	28,691	22,170
Pnm Electric [Member]
Electric Operating Revenues	334,993	326,026	873,434	863,609
Operating Expenses:
Cost of energy	115,097	100,200	304,365	283,715
Administrative and general	37,519	40,679	116,731	116,058
Energy production costs	43,287	41,142	136,422	131,546
Regulatory disallowances	0	1,735	0	1,735
Depreciation and amortization	27,524	25,879	81,629	77,763
Transmission and distribution costs	10,693	11,686	32,202	33,420
Taxes other than income taxes	10,258	9,488	30,359	28,613
Total operating expenses	244,378	230,809	701,708	672,850
Operating income	90,615	95,217	171,726	190,759
Other Income and Deductions:
Interest income	2,102	2,298	6,295	7,839
Gains on available-for-sale securities	962	2,188	8,234	6,935
Other income	1,804	2,398	5,359	5,329
Other (deductions)	(1,197)	(2,375)	(4,844)	(5,287)
Net other income and deductions	3,671	4,509	15,044	14,816
Interest Charges	20,092	20,124	59,927	59,971
Earnings before Income Taxes	74,194	79,602	126,843	145,604
Income Taxes	25,142	27,652	42,331	49,184
Net Earnings	49,052	51,950	84,512	96,420
(Earnings) Attributable to Valencia Non-controlling Interest	(3,701)	(4,127)	(11,140)	(10,904)
Preferred Stock Dividend Requirements	(132)	(132)	(396)	(396)
Net Earnings Attributable to PNMR	45,351	47,823	73,372	85,516
Net Earnings Available for PNM Common Stock	$ 45,219	$ 47,691	$ 72,976	$ 85,120

XML

Fair Value of Derivative and Other Financial Instruments, Recurring (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 235,894	$ 226,855
PNM Resources [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,072,872	1,905,230
Investment In PVNGS lessor notes	32,712	57,279
Other investments	2,406	3,196
PNM Resources [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment In PVNGS lessor notes	0	0
Other investments	546	690
PNM Resources [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,072,872	1,905,230
Investment In PVNGS lessor notes	0	0
Other investments	0	0
PNM Resources [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment In PVNGS lessor notes	32,712	57,279
Other investments	1,860	2,506
Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,525,625	1,382,938
Investment In PVNGS lessor notes	32,712	57,279
Other investments	300	445
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment In PVNGS lessor notes	0	0
Other investments	300	445
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,525,625	1,382,938
Investment In PVNGS lessor notes	0	0
Other investments	0	0
Public Service Company of New Mexico [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment In PVNGS lessor notes	32,712	57,279
Other investments	0	0
Texas-New Mexico Power Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	422,583	390,814
Other investments	245	245
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	245	245
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	422,583	390,814
Other investments	0	0
Texas-New Mexico Power Company [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	0	0
Reported Value Measurement [Member] | PNM Resources [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,875,172	1,745,420
Investment In PVNGS lessor notes	31,469	52,958
Other investments	1,667	1,835
Reported Value Measurement [Member] | Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,390,647	1,290,618
Investment In PVNGS lessor notes	31,469	52,958
Other investments	300	445
Reported Value Measurement [Member] | Texas-New Mexico Power Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	365,759	336,036
Other investments	245	245
Cash and equivalents [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,338	3,356
Domestic value [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	41,917	39,460
Domestic growth [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	74,647	76,292
International and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	16,957	16,633
U.S. Government [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	19,616	21,941
Municipals [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	67,595	58,568
Corporate and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	11,824	10,605
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	235,894	226,855
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	157,268	158,180
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	78,626	68,675
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	5,232	7,066
Commodity derivative instruments, Liabilities	(2,058)	(3,793)
Commodity derivative instruments, Net	3,174	3,273
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	0	0
Commodity derivative instruments, Liabilities	0	0
Commodity derivative instruments, Net	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	5,232	7,066
Commodity derivative instruments, Liabilities	(2,058)	(3,793)
Commodity derivative instruments, Net	3,174	3,273
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,338	3,356
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,338	3,356
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	41,917	39,460
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	41,917	39,460
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	74,647	76,292
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	74,647	76,292
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	16,957	16,633
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	16,957	16,633
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	19,616	21,941
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,865	20,194
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,751	1,747
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	67,595	58,568
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	67,595	58,568
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	11,824	10,605
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	2,544	2,245
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 9,280	$ 8,360

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 Pnm Electric [Member]	Dec. 31, 2013 Pnm Electric [Member]	Sep. 30, 2014 Tnmp Electric [Member]	Dec. 31, 2013 Tnmp Electric [Member]
Current Assets:
Cash and cash equivalents	$ 28,424	$ 2,533	$ 625	$ 21	$ 1	$ 1
Accounts receivable, net of allowance for uncollectible accounts	105,516	90,251	78,811	70,126	26,705	20,125
Unbilled revenues	63,253	58,806	54,643	48,992	8,610	9,814
Other receivables	39,061	53,909	38,799	52,964	679	1,246
Affiliate receivables			9,572	10,054
Materials, supplies, and fuel stock	63,637	67,223	60,731	64,520	2,906	2,703
Regulatory assets	41,606	24,416	38,328	19,394	3,278	5,022
Commodity derivative instruments	4,148	4,064	4,148	4,064
Income taxes receivable	6,723	7,066	6,797	4,030
Current portion of accumulated deferred income taxes	58,681	58,681	43,826	43,827	6,501	6,501
Other current assets	55,277	34,590	49,533	30,510	1,672	980
Total current assets	466,326	401,539	385,813	348,502	50,352	46,392
Other Property and Investments:
Investment in PVNGS lessor notes	9,775	32,200	9,775	32,200
Available-for-sale securities	235,894	226,855	235,894	226,855
Other investments	1,667	1,835	300	445	245	245
Non-utility property	4,060	4,353	752	976	2,240	2,240
Total other property and investments	251,396	265,243	246,721	260,476	2,485	2,485
Utility Plant:
Plant in service and plant held for future use	5,754,564	5,563,061	4,460,035	4,314,016	1,127,872	1,074,193
Less accumulated depreciation and amortization	1,913,361	1,838,832	1,469,375	1,402,531	369,426	352,105
Net plant in service and plant held for future use	3,841,203	3,724,229	2,990,660	2,911,485	758,446	722,088
Construction work in progress	211,472	132,080	167,180	107,344	36,841	16,790
Nuclear fuel, net of accumulated amortization	81,840	77,602	81,840	77,602
Net utility plant	4,134,515	3,933,911	3,239,680	3,096,431	795,287	738,878
Deferred Charges and Other Assets:
Regulatory assets	479,138	523,955	347,642	384,217	131,496	139,738
Goodwill	278,297	278,297	51,632	51,632	226,665	226,665
Commodity derivative instruments	1,084	3,002	1,084	3,002
Other deferred charges	98,453	94,263	85,902	83,356	10,260	8,273
Total deferred charges and other assets	856,972	899,517	486,260	522,207	368,421	374,676
Total assets	5,709,209	5,500,210	4,358,474	4,227,616	1,216,545	1,162,431
Current Liabilities:
Short-term debt	100,000	149,200	0	49,200
Short-term debt - affiliate			6,500	32,500
Short-term debt – affiliate					19,100	29,400
Current installments of long-term debt	333,066	75,000	214,300	75,000
Accounts payable	102,656	109,666	83,741	84,643	9,584	12,543
Affiliate payables			14,692	20,498	1,758	3,181
Customer deposits	12,483	13,456	12,483	13,456
Accrued interest and taxes	82,052	49,600	51,188	27,665	42,831	23,778
Regulatory liabilities	1,126	1,081	1,126	1,081
Commodity derivative instruments	1,370	2,699	1,370	2,699
Dividends declared	14,868	14,864	132	132
Other current liabilities	52,671	77,105	35,576	50,392	2,491	8,999
Total current liabilities	700,292	492,671	421,108	357,266	75,764	77,901
Long-term Debt	1,542,106	1,670,420	1,176,347	1,215,618	365,759	336,036
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	884,402	801,408	714,983	651,239	201,441	190,197
Accumulated deferred investment tax credits	24,232	25,855	24,232	25,855
Regulatory liabilities	472,054	460,649	425,062	414,611	46,992	46,038
Asset retirement obligations	102,115	96,135	101,147	95,225	831	782
Accrued pension liability and postretirement benefit cost	69,363	80,046	66,183	76,611	3,180	3,435
Commodity derivative instruments	688	1,094	688	1,094
Other deferred credits	104,270	109,805	87,264	91,340	7,283	5,111
Total deferred credits and other liabilities	1,657,124	1,574,992	1,419,559	1,355,975	259,727	245,563
Total liabilities	3,899,522	3,738,083	3,017,014	2,928,859	701,250	659,500
Commitments and Contingencies (See [Note 11])
Cumulative preferred stock of subsidiary without mandatory redemption requirements	11,529	11,529	11,529	11,529
Company common stockholders’ equity:
Common stock outstanding	1,172,876	1,178,369	1,061,776	1,061,776	64	64
Paid-in-capital					404,166	404,166
Accumulated other comprehensive income (loss), net of income taxes	(56,532)	(58,140)	(56,278)	(57,877)	(254)	(263)
Retained earnings	606,394	553,340	249,013	206,300	111,319	98,964
Total Company common stockholders' equity	1,722,738	1,673,569	1,254,511	1,210,199	515,295	502,931
Non-controlling interest in Valencia	75,420	77,029	75,420	77,029
Total equity	1,798,158	1,750,598	1,329,931	1,287,228
Total liabilities and stockholders' equity	$ 5,709,209	$ 5,500,210	$ 4,358,474	$ 4,227,616	$ 1,216,545	$ 1,162,431

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Earnings Per Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Earnings Per Share [Abstract]
Net Earnings Attributable to PNMR	$ 55,653		$ 54,555		$ 97,262		$ 92,859
Average Number of Common Shares:
Outstanding during period	79,654,000		79,654,000		79,654,000		79,654,000
Vested awards of restricted stock	112,000		177,000		134,000		194,000
Average Shares – Basic	79,766,000		79,831,000		79,788,000		79,848,000
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	457,000	[1]	503,000	[1]	491,000	[1]	608,000	[1]
Average Shares – Diluted	80,223,000		80,334,000		80,279,000		80,456,000
Net Earnings Per Share of Common Stock:
Basic (dollars per share)	$ 0.70		$ 0.68		$ 1.22		$ 1.16
Diluted (dollars per share)	$ 0.69		$ 0.68		$ 1.21		$ 1.15
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares)					435,472

[1] Excludes the effect of out-of-the-money options for 435,472 shares of common stock at September 30, 2014.

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Related Party Transactions

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(In thousands)
Services billings:
PNMR to PNM	$	20,813	$	22,241	$	64,069	$	65,729
PNMR to TNMP	6,471		6,731		20,695		20,948
PNM to TNMP	142		140		402		381
TNMP to PNMR	20		2		21		6
Interest billings:
PNMR to TNMP	65		139		245		354
PNMR to PNM	1		—		55		1
PNM to PNMR	28		35		79		113
Income tax sharing payments:
PNMR to PNM	—		—		—		45,000
PNMR to TNMP	—		—		—		—

XML

Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	$ 413,951	$ 399,730	$ 1,089,008	$ 1,064,993
Cost of energy	132,499	114,674	354,532	325,039
Margin	281,452	285,056	734,476	739,954
Other operating expenses	120,358	124,574	369,203	368,454
Depreciation and amortization	44,295	42,743	128,424	125,189
Operating income	116,799	117,739	236,849	246,311
Interest income	2,084	2,264	6,241	7,731
Other income (deductions)	1,773	(528)	8,697	996
Net interest charges	(30,115)	(30,365)	(89,621)	(92,279)
Earnings before Income Taxes	90,541	89,110	162,166	162,759
Income taxes (benefit)	31,055	30,296	53,368	58,600
Segment earnings (loss)	59,486	58,814	108,798	104,159
Valencia non-controlling interest	(3,701)	(4,127)	(11,140)	(10,904)
Dividends declared on preferred stock	(132)	(132)	(396)	(396)
Segment earnings (loss) attributable to PNMR	55,653	54,555	97,262	92,859
Total Assets	5,709,209	5,428,814	5,709,209	5,428,814	5,500,210
Goodwill	278,297	278,297	278,297	278,297	278,297
Pnm Electric [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	334,993	326,026	873,434	863,609
Cost of energy	115,097	100,200	304,365	283,715
Margin	219,896	225,826	569,069	579,894
Other operating expenses	101,757	104,730	315,714	311,372
Depreciation and amortization	27,524	25,879	81,629	77,763
Operating income	90,615	95,217	171,726	190,759
Interest income	2,102	2,298	6,295	7,839
Other income (deductions)	1,569	2,211	8,749	6,977
Net interest charges	(20,092)	(20,124)	(59,927)	(59,971)
Earnings before Income Taxes	74,194	79,602	126,843	145,604
Income taxes (benefit)	25,142	27,652	42,331	49,184
Segment earnings (loss)	49,052	51,950	84,512	96,420
Valencia non-controlling interest	(3,701)	(4,127)	(11,140)	(10,904)
Dividends declared on preferred stock	(132)	(132)	(396)	(396)
Segment earnings (loss) attributable to PNMR	45,219	47,691	72,976	85,120
Total Assets	4,358,474	4,192,470	4,358,474	4,192,470	4,227,616
Goodwill	51,632	51,632	51,632	51,632	51,632
Tnmp Electric [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	78,958	73,704	215,574	201,384
Cost of energy	17,402	14,474	50,167	41,324
Margin	61,556	59,230	165,407	160,060
Other operating expenses	22,251	23,126	63,732	67,274
Depreciation and amortization	13,432	13,850	37,276	37,810
Operating income	25,873	22,254	64,399	54,976
Interest income	0	0	0	0
Other income (deductions)	793	716	1,495	1,409
Net interest charges	(6,870)	(6,655)	(20,122)	(20,661)
Earnings before Income Taxes	19,796	16,315	45,772	35,724
Income taxes (benefit)	7,441	6,209	17,081	13,554
Segment earnings (loss)	12,355	10,106	28,691	22,170
Valencia non-controlling interest	0	0	0	0
Dividends declared on preferred stock	0	0	0	0
Segment earnings (loss) attributable to PNMR	12,355	10,106	28,691	22,170
Total Assets	1,216,545	1,162,587	1,216,545	1,162,587	1,162,431
Goodwill	226,665	226,665	226,665	226,665	226,665
Corporate and Other [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	0	0	0	0
Cost of energy	0	0	0	0
Margin	0	0	0	0
Other operating expenses	(3,650)	(3,282)	(10,243)	(10,192)
Depreciation and amortization	3,339	3,014	9,519	9,616
Operating income	311	268	724	576
Interest income	(18)	(34)	(54)	(108)
Other income (deductions)	(589)	(3,455)	(1,547)	(7,390)
Net interest charges	(3,153)	(3,586)	(9,572)	(11,647)
Earnings before Income Taxes	(3,449)	(6,807)	(10,449)	(18,569)
Income taxes (benefit)	(1,528)	(3,565)	(6,044)	(4,138)
Segment earnings (loss)	(1,921)	(3,242)	(4,405)	(14,431)
Valencia non-controlling interest	0	0	0	0
Dividends declared on preferred stock	0	0	0	0
Segment earnings (loss) attributable to PNMR	(1,921)	(3,242)	(4,405)	(14,431)
Total Assets	134,190	73,757	134,190	73,757
Goodwill	$ 0	$ 0	$ 0	$ 0

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Significant Accounting Policies and Responsibility for Financial Statements (Policies)

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM began consolidating Rio Bravo, formerly known as Delta, upon its acquisition on July 17, 2014. PNM also consolidates the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 14.

Dividends on Common Stock

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.185 per share in July 2014 and $0.165 in July 2013, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. The Board declared dividends on common stock considered to be for the third quarter of $0.185 per share in September 2014 and $0.165 in September 2013, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

PNM declared and paid cash dividends on its common stock to PNMR of $30.3 million and $68.0 million in the nine months ended September 30, 2014 and 2013. TNMP declared and paid cash dividends of $16.3 million and $3.7 million in the nine months ended September 30, 2014 and 2013.

New Accounting Pronouncements

New Accounting Pronouncements

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

Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606)

On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for the Company beginning on January 1, 2017. Early adoption is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

Accounting Standards Update 2014-12 – Compensation-Stock Compensation (Topic 718) Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period

On June 19, 2014, the FASB issued ASU No. 2014-12, which requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in estimating the grant date fair value of the award. The new standard is effective for the Company beginning on January 1, 2016. Early adoption is permitted and the standard permits the use of either the prospective or retrospective transition methods. Although the Company is in the process of analyzing the impacts this new standard will have on its consolidated financial statements, the Company currently treats the performance targets covered by the standard as performance conditions, so the Company does not expect its impact will be significant.

Consolidation, Variable Interest Entity

GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity.

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Allowance for uncollectible accounts	$ 1,535	$ 1,423
Accumulated depreciation, nuclear fuel	52,119	47,347
Cumulative preferred stock of subsidiary, stated value	$ 100	$ 100
Cumulative preferred stock of subsidiary, shares authorized	10,000,000	10,000,000
Cumulative preferred stock of subsidiary, shares issued	115,293	115,293
Cumulative preferred stock of subsidiary, shares authorized	115,293	115,293
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	79,653,624	79,653,624
Common stock, shares outstanding	79,653,624	79,653,624
Tnmp Electric [Member]
Common stock, par value	$ 10	$ 10
Common stock, shares authorized	12,000,000	12,000,000
Common stock, shares issued	6,358	6,358
Common stock, shares outstanding	6,358	6,358
Pnm Electric [Member]
Allowance for uncollectible accounts	1,535	1,423
Accumulated depreciation, nuclear fuel	$ 52,119	$ 47,347
Cumulative preferred stock, stated value	$ 100	$ 100
Cumulative preferred stock, shares authorized	10,000,000	10,000,000
Cumulative preferred stock, shares issued	115,293	115,293
Cumulative preferred stock, shares outstanding	115,293	115,293
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares issued	39,117,799	39,117,799
Common stock, shares outstanding	39,117,799	39,117,799

XML

Condensed Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Net Earnings	$ 59,486	$ 58,814	$ 108,798	$ 104,159
Net earnings	55,653	54,555	97,262	92,859
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	210	6,322	6,256	11,512
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(1,628)	(1,411)	(6,997)	(5,551)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit)	780	960	2,340	2,880
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	0	(238)	(100)	(236)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	(6)	35	109	99
Net change after income taxes	(644)	5,668	1,608	8,704
Comprehensive Income	58,842	64,482	110,406	112,863
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,701)	(4,127)	(11,140)	(10,904)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(396)	(396)
Comprehensive Income Attributable to PNMR	55,009	60,223	98,870	101,563
Public Service Company of New Mexico [Member]
Fair Value Adjustment for Cash Flow Hedges:
Net change after income taxes			1,599	8,841
Texas-New Mexico Power Company [Member]
Fair Value Adjustment for Cash Flow Hedges:
Net change after income taxes			9	(137)
Pnm Electric [Member]
Net Earnings	49,052	51,950	84,512	96,420
Net earnings	45,351	47,823	73,372	85,516
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	210	6,322	6,256	11,512
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(1,628)	(1,411)	(6,997)	(5,551)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit)	780	960	2,340	2,880
Fair Value Adjustment for Cash Flow Hedges:
Net change after income taxes	(638)	5,871	1,599	8,841
Comprehensive Income	48,414	57,821	86,111	105,261
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,701)	(4,127)	(11,140)	(10,904)
Comprehensive Income Attributable to PNMR	44,713	53,694	74,971	94,357
Tnmp Electric [Member]
Net Earnings	12,355	10,106	28,691	22,170
Net earnings	12,355	10,106	28,691	22,170
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	0	(238)	(100)	(236)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	(6)	35	109	99
Net change after income taxes	(6)	(203)	9	(137)
Comprehensive Income Attributable to PNMR	$ 12,349	$ 9,903	$ 28,700	$ 22,033

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Financing

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Financing

Financing

Additional information concerning financing activities, including a TNMP cash-flow hedge, which terminated on June 27, 2014, that established a fixed interest rate on a variable rate loan, is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Financing Activities

On January 8, 2014, PNM entered into a new $50.0 million unsecured revolving credit facility (the “PNM New Mexico Credit Facility”) by and among PNM, the lenders identified therein, U.S. Bank National Association, as Administrative Agent, and BOKF, NA dba Bank of Albuquerque, as Syndication Agent. The nine participating lenders are all banks that have a significant presence in New Mexico and PNM’s service territory or are headquartered in New Mexico. The PNM New Mexico Credit Facility expires on January 8, 2018 and contains covenants and conditions similar to those in the PNM Revolving Credit Facility.

On March 5, 2014, PNM entered into a new $175.0 million Term Loan Agreement (the “PNM 2014 Term Loan Agreement”) among PNM and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Lender and Administrative Agent. On March 5, 2014, PNM used a portion of the funds borrowed under the PNM 2014 Term Loan Agreement to repay all amounts outstanding under PNM’s existing $75.0 million PNM Term Loan Agreement. PNM also used the funds to repay other short-term amounts outstanding. The PNM Term Loan Agreement would otherwise have terminated on October 21, 2014. There were no prepayment penalties paid in connection with the termination of the PNM Term Loan Agreement. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.10% at September 30, 2014, must be repaid on or before September 4, 2015, and is reflected in current maturities of long-term debt on the Condensed Consolidated Balance Sheets. The PNM 2014 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNM 2014 Term Loan Agreement has a cross default provision and a change of control provision.

On December 9, 2013, TNMP entered into an agreement (the “TNMP 2013 Bond Purchase Agreement”), which provided that TNMP would issue $80.0 million aggregate principal amount of 4.03% first mortgage bonds, due 2024 (the “Series 2014A Bonds”) on or about June 27, 2014, subject to satisfaction of certain conditions. TNMP issued the Series 2014A Bonds on June 27, 2014. TNMP used $50.0 million of the proceeds to repay the full outstanding amount of the TNMP 2011 Term Loan Agreement and used the remaining $30.0 million of proceeds to reduce short-term debt. In accordance with GAAP, borrowings under the TNMP 2011 Term Loan Agreement were reflected as being long-term at December 31, 2013 since the TNMP 2013 Bond Purchase Agreement demonstrated TNMP’s ability and intent to re-finance the TNMP 2011 Term Loan Agreement on a long-term basis.

Short-term Debt

PNMR has a revolving credit financing capacity of $300.0 million under the PNMR Revolving Credit Facility. PNM has a revolving credit financing capacity of $400.0 million under the PNM Revolving Credit Facility. Both of these facilities currently expire on October 31, 2018. TNMP has a revolving credit financing capacity of $75.0 million under the TNMP Revolving Credit Facility that is secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds and matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At September 30, 2014, there were no borrowings under any of these facilities. At September 30, 2014, PNM had $6.5 million and TNMP had $19.1 million in borrowings from PNMR under their intercompany loan agreements. At September 30, 2014, the weighted average interest rate was 1.01% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2014. Short-term debt outstanding consisted of:

	September 30,		December 31,
Short-term Debt	2014		2013
	(In thousands)
PNM:
Revolving credit facility	$	—	$	49,200
PNM New Mexico Credit Facility	—		—
TNMP – Revolving credit facility	—		—
PNMR:
Revolving credit facility	—		—
PNMR Term Loan Agreement	100,000		100,000
	$	100,000	$	149,200

At October 24, 2014, PNMR, PNM, and TNMP had $292.3 million, $396.8 million, and $74.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $50.0 million of availability under the PNM New Mexico Credit Facility. Total availability at October 24, 2014, on a consolidated basis, was $814.0 million for PNMR. As of October 24, 2014, PNM had $7.4 million and TNMP had $25.7 million in borrowings from PNMR under their intercompany loan agreements. At October 24, 2014, PNMR, PNM and TNMP had consolidated invested cash of $23.1 million, none, and none.

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 24, 2014
Document Information [Line Items]
Entity Registrant Name	PNM RESOURCES INC
Entity Central Index Key	0001108426
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		79,653,624
Public Service Company of New Mexico [Member]
Document Information [Line Items]
Entity Registrant Name	PUBLIC SERVICE CO OF NEW MEXICO
Entity Central Index Key	0000081023
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		39,117,799
Texas-New Mexico Power Company [Member]
Document Information [Line Items]
Entity Registrant Name	TEXAS NEW MEXICO POWER CO
Entity Central Index Key	0000022767
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		6,358

XML

Pension and Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2014

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefit Plans

Pension and Other Postretirement Benefit Plans

PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans.

Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. The Society of Actuaries recently issued revised mortality tables that include changes in assumptions to reflect increased life expectancy and the corresponding decrease in mortality rates.  This change will have impacts on the Company’s pension plans, as the mortality assumptions are used as the basis for stating the pension obligation in financial statements, determining funding requirements, and making minimum lump-sum calculations.  The Company, with the assistance of its consulting actuaries, is studying the impact of the mortality table changes.  This study is on-going and subject to change.  Preliminary estimates indicate that the Company’s pension liabilities reflecting the new mortality tables and other current assumptions could increase by approximately 7% over those previously reported.  Although pension expense and funding requirements also will likely increase, these changes are not expected to be material.

PNM Plans

The following tables present the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	45		$	65		$	—	$	—
Interest cost	7,541			7,035			1,159			1,029			205		180
Expected return on plan assets	(9,511		)	(10,482		)	(1,410		)	(1,261		)	—		—
Amortization of net (gain) loss	3,255			3,710			556			1,061			52		58
Amortization of prior service cost	(241		)	19			(336		)	(336		)	—		—
Net periodic benefit cost	$	1,044		$	282		$	14		$	558		$	257	$	238
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	136		$	195		$	—	$	—
Interest cost	22,622			21,106			3,473			3,085			616		540
Expected return on plan assets	(28,533		)	(31,447		)	(4,229		)	(3,782		)	—		—
Amortization of net (gain) loss	9,765			11,130			1,669			3,182			157		174
Amortization of prior service cost	(724		)	57			(1,008		)	(1,008		)	—		—
Net periodic benefit cost	$	3,130		$	846		$	41		$	1,672		$	773	$	714

PNM does not anticipate making any contributions to its pension trust in 2014 due to the current funded status of the pension plan.  PNM made contributions to its pension plan trust of zero and $60.0 million in the three and nine months ended September 30, 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the PNM pension plan trust for 2015-2018 are estimated to total $50.0 million. These anticipated contributions were developed using current funding assumptions, with discount rates of 4.5% to 5.3%. Actual amounts required to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made contributions to the OPEB trust of $0.8 million and $2.4 million in the three and nine months ended September 30, 2014 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2013. PNM expects to make contributions to the OPEB trust totaling $3.3 million in 2014 and $14.0 million for 2015-2018.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.2 million in the three and nine months ended September 30, 2014 and $0.4 million and $1.1 million in the three and nine months ended September 30, 2013 and are expected to total $1.6 million during 2014.

TNMP Plans

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

	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	59		$	75		$	—	$	—
Interest cost	798			772			155			141			10		9
Expected return on plan assets	(1,132		)	(1,212		)	(133		)	(126		)	—		—
Amortization of net (gain) loss	166			262			(31		)	—			—		—
Amortization of prior service cost	—			—			8			14			—		—
Net Periodic Benefit Cost (Income)	$	(168	)	$	(178	)	$	58		$	104		$	10	$	9
	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	178		$	225		$	—	$	—
Interest cost	2,395			2,315			464			424			29		27
Expected return on plan assets	(3,395		)	(3,637		)	(400		)	(377		)	—		—
Amortization of net (gain) loss	499			787			(92		)	—			—		—
Amortization of prior service cost	—			—			24			43			—		—
Net Periodic Benefit Cost (Income)	$	(501	)	$	(535	)	$	174		$	315		$	29	$	27

TNMP does not anticipate making additional contributions to its pension trust in 2014 due to the current funded status of the pension plan. TNMP made contributions to its pension plan trust of zero and $1.0 million in the three and nine months ended September 30, 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, TNMP estimates there would be no contributions to its pension plan trust for 2015-2018. The anticipated contributions were developed using current funding assumptions, including discount rates of 4.5% and 5.3%. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions to the OPEB trust of zero and $0.3 million in the three and nine months ended September 30, 2014 and zero and $0.3 million in the three and nine months ended September 30, 2013. TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2014 and $1.4 million for 2015-2018. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three and nine months ended September 30, 2014 and 2013 and are expected to total $0.1 million during 2014.

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Unrealized holding gains (losses) arising during the period, income tax (expense)	$ (137)	$ (4,143)	$ (3,946)	$ (7,544)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	1,059	925	4,547	3,639
Pension liability adjustment, income tax (expense) benefit	(508)	(631)	(1,524)	(1,893)
Change in fair market value, income tax (expense)	0	128	53	127
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	3	(19)	(58)	(54)
Tnmp Electric [Member]
Change in fair market value, income tax (expense)	0	128	53	127
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	3	(19)	(58)	(54)
Pnm Electric [Member]
Unrealized holding gains (losses) arising during the period, income tax (expense)	(137)	(4,143)	(3,946)	(7,544)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	1,059	925	4,547	3,639
Pension liability adjustment, income tax (expense) benefit	$ (508)	$ (631)	$ (1,524)	$ (1,893)

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Accumulated Other Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2014 and 2013 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	Unrealized						Fair Value
	Gain on			Pension			Adjustment
	Available-for-			Liability			for Cash Flow
	Sale Securities			Adjustment			Hedges			Total
	(In thousands)
PNMR
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(263	)	$	(58,140	)
Amounts reclassified from AOCI (pre-tax)	(11,544		)	3,864			167			(7,513		)
Income tax impact of amounts reclassified	4,547			(1,524		)	(58		)	2,965
Other OCI changes (pre-tax)	10,202			—			(153		)	10,049
Income tax impact of other OCI changes	(3,946		)	—			53			(3,893		)
Net change after income taxes	(741		)	2,340			9			1,608
Balance at September 30, 2014	$	25,007		$	(81,285	)	$	(254	)	$	(56,532	)

PNM
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	—	$	(57,877	)
Amounts reclassified from AOCI (pre-tax)	(11,544		)	3,864			—		(7,680		)
Income tax impact of amounts reclassified	4,547			(1,524		)	—		3,023
Other OCI changes (pre-tax)	10,202			—			—		10,202
Income tax impact of other OCI changes	(3,946		)	—			—		(3,946		)
Net change after income taxes	(741		)	2,340			—		1,599
Balance at September 30, 2014	$	25,007		$	(81,285	)	$	—	$	(56,278	)

TNMP
Balance at December 31, 2013	$	—	$	—	$	(263	)	$	(263	)
Amounts reclassified from AOCI (pre-tax)	—		—		167			167
Income tax impact of amounts reclassified	—		—		(58		)	(58		)
Other OCI changes (pre-tax)	—		—		(153		)	(153		)
Income tax impact of other OCI changes	—		—		53			53
Net change after income taxes	—		—		9			9
Balance at September 30, 2014	$	—	$	—	$	(254	)	$	(254	)

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

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

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

Pre-tax amounts reclassified from AOCI related to “Unrealized Gain on Available-for-Sale Securities” are included in “Gains on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “Pension Liability Adjustment” are reclassified to “Operating Expenses – Administrative and general” in the Condensed Consolidated Statements of Earnings. For the nine months ended September 30, 2014 and 2013, approximately 23.6% and 19.6% of the amount reclassified was capitalized into construction work in process and approximately 1.7% and 1.1% was capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes” in the Condensed Consolidated Statements of Earnings.

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Segment Information

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Segment Information

Segment Information

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

PNM

PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also provides generation service to firm-requirements wholesale customers and sells electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM’s jurisdictional capacity, as well as the capacity from PVNGS Unit 3, which currently is not included in retail rates. FERC has jurisdiction over wholesale and transmission rates.

TNMP

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

Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company.

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

PNMR SEGMENT INFORMATION

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2014
Electric operating revenues	$	334,993		$	78,958		$	—		$	413,951
Cost of energy	115,097			17,402			—			132,499
Margin	219,896			61,556			—			281,452
Other operating expenses	101,757			22,251			(3,650		)	120,358
Depreciation and amortization	27,524			13,432			3,339			44,295
Operating income	90,615			25,873			311			116,799
Interest income	2,102			—			(18		)	2,084
Other income (deductions)	1,569			793			(589		)	1,773
Net interest charges	(20,092		)	(6,870		)	(3,153		)	(30,115		)
Segment earnings (loss) before income taxes	74,194			19,796			(3,449		)	90,541
Income taxes (benefit)	25,142			7,441			(1,528		)	31,055
Segment earnings (loss)	49,052			12,355			(1,921		)	59,486
Valencia non-controlling interest	(3,701		)	—			—			(3,701		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	45,219		$	12,355		$	(1,921	)	$	55,653
Nine Months Ended September 30, 2014
Electric operating revenues	$	873,434		$	215,574		$	—		$	1,089,008
Cost of energy	304,365			50,167			—			354,532
Margin	569,069			165,407			—			734,476
Other operating expenses	315,714			63,732			(10,243		)	369,203
Depreciation and amortization	81,629			37,276			9,519			128,424
Operating income	171,726			64,399			724			236,849
Interest income	6,295			—			(54		)	6,241
Other income (deductions)	8,749			1,495			(1,547		)	8,697
Net interest charges	(59,927		)	(20,122		)	(9,572		)	(89,621		)
Segment earnings (loss) before income taxes	126,843			45,772			(10,449		)	162,166
Income taxes (benefit)	42,331			17,081			(6,044		)	53,368
Segment earnings (loss)	84,512			28,691			(4,405		)	108,798
Valencia non-controlling interest	(11,140		)	—			—			(11,140		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	72,976		$	28,691		$	(4,405	)	$	97,262
At September 30, 2014:
Total Assets	$	4,358,474		$	1,216,545		$	134,190		$	5,709,209
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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

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Goodwill

9 Months Ended

Sep. 30, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM.

GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. PNMR's reporting units that have goodwill are PNM and TNMP. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit.

GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity would consider macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity would consider the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit's fair value with its carrying amount. An entity should place more weight on the events and circumstances that most affect a reporting unit's fair value or the carrying amount of its net assets. An entity also should consider positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity would evaluate, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis is not required.

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations.

An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units but a quantitative analysis for others. For the annual evaluations performed as of April 1, 2014 and 2013, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit. For the PNM reporting unit, a discounted cash flow methodology was primarily used to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment.

The annual evaluations performed as of April 1, 2014 and 2013 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2014 and 2013 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 30% and 27%. The last quantitative evaluation performed for the TNMP reporting unit on April 1, 2012 indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 26%. Since the April 1, 2014 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill is contained in Note 21 of Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company occasionally enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 12) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.

With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Commitments and Contingencies Related to the Environment

Nuclear Spent Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. In 2010, the court ordered an award to the PVNGS owners for their damages claim for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, and on October 7, 2014, APS received a settlement payment of $57.4 million for costs paid through June 30, 2011, for DOE’s failure to accept spent nuclear fuel generated at PVNGS. PNM’s share of the settlement is $5.9 million, which was recorded in other deferred credits. The settlement agreement also establishes a process for the payment of subsequent claims through December 30, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. The first claim is due no later than October 31, 2014, for costs paid between July 1, 2011, and June 30, 2014. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At September 30, 2014 and December 31, 2013, PNM had a liability for interim storage costs of $12.2 million and $11.9 million included in other deferred credits.

On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high-level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision. The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which requires either an EIS or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action. In September 2012, the NRC issued a directive to its staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision within 24 months. In September 2013, the NRC issued its draft EIS to support an updated Waste Confidence Decision. In late 2013, the NRC held a series of nationwide public meetings to receive stakeholder input on the draft EIS. In September 2014, the NRC issued its final rule codifying the results of analyses from a generic EIS regarding the continued storage of spent nuclear fuel.  The rule became effective on October 20, 2014. Untimely resolution by the NRC of the remand from the D.C. Circuit could have an adverse impact on certain NRC licensing actions. Currently, PVNGS does not have any licensing actions pending with the NRC. The petitioners also sought a writ requiring the NRC to comply with the law and resume processing DOE’s pending license application for a nuclear waste site at Yucca Mountain in Nevada. In August 2013, the D.C. Circuit ordered the NRC to resume reviewing the license application. PNM is unable to predict the impact of these decisions.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of the intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of the intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. On May 16, 2014, the DOE adjusted the fee to zero. In 2013, the one-mill fee for PNM’s share of the output from all three units at PVNGS amounted to $3.0 million. The fee applicable to PVNGS Units 1 and 2 is recovered by PNM in its retail rates. PNM anticipates challenges to this action and is unable to predict its ultimate outcome.

The Clean Air Act

Regional Haze

In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.

SJGS

BART Determination Process –SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that required installation of selective catalytic reduction technology (“SCR”) on all four units by September 21, 2016. In November 2012, EPA approved all components of the SIP, except for the NOx BART determination for SJGS, which continued to be subject to the FIP.

PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA’s decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule. These parties also formally asked EPA to stay the effective date of the rule. Several environmental groups intervened in support of EPA. The parties file periodic status reports with the Tenth Circuit, but proceedings are being held in abeyance as agreed to by the parties.

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

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

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013, reflecting the terms of the non-binding agreement. NMED developed a RSIP and submitted it to the EIB for approval in May 2013. The EIB approved the RSIP in September 2013 and it was submitted to EPA for approval on October 18, 2013. EPA published its proposed approval of the RSIP in the Federal Register on May 12, 2014. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and will become effective on November 10, 2014. The deadline for filing petitions for review is December 8, 2014.

Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM took steps to commence installation of SCRs at SJGS. In October 2012, PNM entered into a contract 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 December 31, 2014. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million. The costs for the project to install SCRs would encompass installation of technology to comply with the NAAQS requirements described below.

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

The above estimates include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM’s share under either SCRs or SNCRs as described above would be about 46.3%.

Following the February 2013 development of the alternative BART compliance plan, PNM began taking steps to prepare for the potential installation of SNCRs on Units 1 and 4 due to the long lead times on certain equipment purchases. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider. In July 2014, PNM entered into a contract for management of the SNCR construction and in September 2014 entered into a construction and procurement contract.

NMPRC Filing – On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. In this filing, PNM requested:

• Permission to retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date along with a regulated return on those costs

• A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018

• An order allowing cost recovery for PNM’s share of the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million

• A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM; the net impact of this exchange and the retirement of Units 2 and 3 would be a reduction of 340 MW in PNM’s ownership of SJGS

The December 20, 2013 NMPRC filing identified a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM has included the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. A proposed stipulated settlement, which is pending approval before the NMPRC, would provide that the additional solar capacity be recovered in base rates rather than through the renewable energy rider. See Note 12. Specific approvals to acquire the gas facility and the treatment of associated costs will be made in future filings. PNM estimates the cost of these identified resources would be approximately $268.3 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs would be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of SNCRs. See Note 12 for additional information concerning PNM’s filing for NMPRC approvals regarding these matters.

As discussed under SJGS Ownership Restructuring Matters below, the owners of SJGS are attempting to negotiate agreements concerning numerous matters, the resolution of which is necessary in order to facilitate the shutdown of SJGS Units 2 and 3 and comply with the RSIP. PNM’s requests in the December 20, 2013 NMPRC filing were based on the status of the negotiations among the SJGS owners at that time. In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements are memorialized in the resolution and term sheet described below.

On October 1, 2014, PNM, the staff of the NMPRC, the NMAG, New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico filed a stipulation with the NMPRC. NMIEC subsequently joined the agreement. Statements of opposition were filed by New Energy Economy, Southwest Generation, the City of Santa Fe, Santa Fe County, and the Coalition for Clean, Affordable Energy.

Under the terms of the stipulation, PNM:

• Would be authorized to abandon SJGS Units 2 and 3 effective December 31, 2017

• Would be granted a CCN for an additional 132 MW of SJGS Unit 4 capacity as of January 1, 2018 with a rate base value of $26 million plus any reasonable and prudent investments made in Unit 4 prior to that date; PNM would reduce its carrying value of SJGS Unit 3 by this $26 million

• Would recover 50% of the estimated $231 million undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a twenty year period and would include a return on the unrecovered amount at PNM’s WACC; at September 30, 2014, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $284 million

• Would be granted a CCN for 134 MW of PVNGS Unit 3 at a January 1, 2018 value of $221.1 million ($1,650 per KW); PNM’s ownership share of PVNGS would also be subject to a capacity factor performance threshold of 75% for a seven year period beginning January 1, 2018; subject to certain exceptions, if the capacity factor is not achieved in any year, PNM would refund the cost of replacement power through its FPPAC; at September 30, 2014, PNM’s net book value of PVNGS Unit 3 was approximately $143 million

• Would recover its reasonable and prudent costs of installation of the SNCRs and equipment to comply with NAAQS requirements at SJGS Units 1 and 4 up to $90.6 million

• Would not be allowed to recover a total of approximately $20 million of increased operations and maintenance costs associated with the agreement reached with the remaining SJGS participants, additional fuel handling expenses, and certain other costs incurred in efforts to comply with the CAA

The public hearing in the NMPRC case is scheduled to begin on January 5, 2015. PNM expects a decision from the NMPRC in the first quarter of 2015. PNM is unable to predict if the NMPRC will approve the stipulation. If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. Although PNM would record the regulatory disallowance upon approval by the NMPRC, the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order, as well as PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3 and PVNGS Unit 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values of the plants. Based on the provisions of the stipulation as filed and PNM’s current projection of December 31, 2017 book values, PNM estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.

SJGS Ownership Restructuring Matters – As discussed in the 2013 Annual Report on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The SJPPA that governs the operation of SJGS expires on July 1, 2022 and the contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. The California participants have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4.

The SJGS participants have engaged in negotiations concerning the implementation of the RSIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 that could have resulted in PNM acquiring additional ownership in Unit 4 prior to the shutdown of SJGS Units 2 and 3. The discussions among the SJGS participants regarding restructuring have also included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs.

On June 26, 2014, a non-binding resolution was unanimously approved by the SJGS Coordination Committee (the “Resolution”). The Resolution identifies the participants who would be exiting active participation in SJGS effective December 31, 2017, and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCRs, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating approximately 59%. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants will need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, the remaining participants are in the process of negotiating agreements concerning future fuel supply for SJGS, the resolution of which is necessary for continued operation of SJGS after December 31, 2017. On September 2, 2014, the SJGS Coordination Committee adopted a non-binding amendment to the Resolution, which provides for allocation of future costs of decommissioning among current SJGS owners using a time-based sliding scale and outlines indemnification obligations.

In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the Resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. PNM filed the Fuel and Capital Funding Agreement with FERC on September 18, 2014, with a request for a retroactive effective date to July 1, 2014. FERC has 60 days from the date of filing to accept the filing. The Fuel and Capital Funding Agreement provides that the SJGS participants will return to the status quo if required regulatory approvals are not obtained or a binding restructuring agreement is not reached.

The participants continue to negotiate other definitive agreements that would formalize the matters contained in the Resolution, as amended. A number of regulatory approvals are required to implement the proposed ownership restructuring of SJGS. Any final binding agreements relating to the ownership restructuring are subject to the approval of each participant’s board or other decision-making body and are subject to required regulatory approvals. PNM is unable to predict the outcome of the negotiations, whether definitive agreements will be reached among the owners, or whether required approvals will be obtained.

Other Developments and Current Status – The SJPPA requires PNM, as operating agent, to obtain approval of capital improvement project expenditures from participants who have an ownership interest in the relevant unit or property common to more than one unit. As provided in the SJPPA, specified percentages of both the outstanding participant shares, based on MW ownership, and the number of participants in the unit or common property must be obtained in order for a capital improvement project to be approved. PNM presented the SNCR project, including NAAQS compliance requirements described below, to the SJGS participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. In addition, other capital projects related to Unit 4 were not approved by the participants. PNM subsequently requested that the owners of Unit 4 approve the expenditure of costs critical to being able to comply with the time frame in the RSIP with respect to the Unit 4 project of $1.9 million on March 10, 2014 and $6.4 million on June 27, 2014. The Unit 4 owners did not approve either of the requests.

PNM, in its capacity as operating agent of SJGS, is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM must evaluate its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and take reasonable and prudent actions as it deems necessary. Therefore, on March 10, 2014 and July 14, 2014, PNM, as operating agent for SJGS, issued “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.

As discussed above, EPA approved the RSIP and withdrew the FIP on October 9, 2014 and those approvals will become effective on November 10, 2014. PNM believes significant progress is being made towards implementation of the RSIP. However, the final implementation of the RSIP is still dependent upon PNM obtaining NMPRC approval to retire San Juan Units 2 and 3 and a final binding agreement among the SJGS owners on a revised ownership structure to facilitate the retirement of these two units. PNM can provide no assurance that these requirements will be accomplished. If the RSIP requirements ultimately are not implemented due to adverse or alternative regulatory, legislative, legal, or restructuring developments or other factors, PNM would need to pursue other alternatives to address compliance with the CAA.PNM will seek recovery from its ratepayers for costs that may be incurred as a result of the CAA requirements. PNM is unable to predict the ultimate outcome of these matters.

Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance its share of the installation. It is possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation or legislation, if any, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant.

Four Corners

On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to close permanently Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were shutdown by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.

APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041.  The Navajo Nation approved these amendments in March 2011.  The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant, which the Four Corners participants are pursuing.  A federal environmental review is underway as part of the DOI review process.  In March 2014, APS received a draft of the EIS in connection with the DOI review process.  On June 19, 2014, PNM submitted comments on the draft EIS as owner and operator of two electric transmission lines that are part of the connected action for the EIS.  In addition, APS will require a PSD permit from EPA to install SCR control technology at Four Corners.  PNM cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners participants.

The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of possible future climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

PNM is continuing to evaluate the impacts of EPA’s BART determination for Four Corners. PNM estimates its share of costs, including PNM’s AFUDC, to be up to $80.3 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM is unable to predict the ultimate outcome of this matter.

Four Corners BART FIP Challenge

On October 22, 2012, WEG filed a petition for review in the Ninth Circuit challenging the Four Corners BART FIP.  In its petition, WEG alleges that the final BART rule results in more air pollution being emitted into the air than allowed by law and that EPA failed to follow the requirements of the ESA.  APS intervened in this matter and filed a motion to dismiss this lawsuit for lack of jurisdiction or alternatively to transfer the lawsuit to the Tenth Circuit. On February 25, 2013, the Ninth Circuit denied APS’ motion to dismiss, but granted the request to transfer the case to the Tenth Circuit. Oral argument was presented before the Tenth Circuit on January 23, 2014. On July 23, 2014, the Tenth Circuit issued a unanimous decision affirming EPA’s action and denying WEG’s petition for review. On September 15, 2014, the Tenth Circuit issued its mandate marking an official end to the case.

Regional Haze Challenges

On December 27, 2012, WEG filed a petition for review in the Tenth Circuit challenging the SO₂ and particulate matter emissions elements of EPA’s approval of New Mexico’s Regional Haze SIP.  On February 26, 2013, HEAL Utah and other environmental groups filed petitions in the Tenth Circuit challenging EPA’s final approval of the remaining elements of New Mexico’s Regional Haze SIP, as well as EPA’s approval of the Albuquerque/Bernalillo County Air Quality Control Board SIP. PNM was granted intervention in both matters and the Tenth Circuit consolidated the two matters based on the similarity of issues. Oral argument was heard before the Tenth Circuit on March 20, 2014. On October 21, 2014, the Tenth Circuit denied the petitions for review and affirmed EPA’s actions. PNM is unable to predict whether petitions for rehearing or appeals of the decision will be filed.

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO₂,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO₂ and the 24-hour SO₂ standard. New Mexico is in attainment for the 1-hour NOx NAAQS. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO₂ NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO₂ sources to identify maximum 1-hour SO₂ concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO₂ sources through ambient monitoring or modeling. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO₂ NAAQS.  Although the determination process has not been finalized, PNM believes that compliance with the 1-hour SO₂ standard may require operational changes and/or equipment modifications at SJGS. On November 8, 2013, PNM received an amendment to its air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. In the revised permit, PNM agreed to reduce SO₂ emissions to 0.1 pound per MMBTU on SJGS Units 1 and 4 and to install equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO₂, and particulate matter. These reductions will help SJGS meet the NAAQS. It is anticipated that the equipment modifications would be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities at SJGS. The cost of this technology is dependent upon the type of control technology that is ultimately determined to be NOx BART at SJGS. See Regional Haze – SJGS above.

EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications discussed above will assist the plant in complying with the particulate matter NAAQS.

In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 0.060-0.070 parts per million. EPA is reviewing its 2008 standard and has completed certain assessment phases of developing a new ozone standard. EPA is under a court order to issue a draft proposal by December 1, 2014 and finalize the new standard by October 1, 2015.  Depending upon where the standard for ozone is set, San Juan County, where SJGS is situated, could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. As a result, SJGS could be required to install further NOx controls to meet a new ozone NAAQS. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional NOx controls would be required at any of its affected facilities as a result of ozone non-attainment designation.

Citizen Suit Under the Clean Air Act

The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS’s emissions performance. In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM’s mercury controls. NMED and plaintiffs sought to require PNM to implement additional mercury controls. PNM estimates the implementation would increase annual mercury control costs for the entire station, which are currently $0.7 million, to a total of $6.6 million. On March 23, 2014, the court entered a stipulated order reflecting an agreement reached by the parties. Under the stipulated order, PNM is required to repeat the mercury study required under the Consent Decree using sorbent traps instead of the monitoring system used in the initial study. PNM has completed stack testing and anticipates finalizing the study report by the end of 2014. The results of the mercury study will establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM cannot predict the ultimate outcome of this matter.

Section 114 Request

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

Four Corners Clean Air Act Lawsuit

In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, the Four Corners participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, the Four Corners owners may reinstate their motions to dismiss without risk of default. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

WEG v. OSM NEPA Lawsuit

In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012.  In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM.  Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine.  WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008.  WEG alleges various National Environmental Policy Act (“NEPA”) violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents.  WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and SJGS. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. Although an agreement was reached resolving claims related to the CAA, the agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.

Cooling Water Intake Structures

EPA issued its final cooling water intake structures rule on May 19, 2014, which establishes national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The final rule was published on August 15, 2014 and became effective October 14, 2014.

The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting “best technology available” standards for reducing impingement. To minimize entrainment mortality, the permitting authority must establish the “best technology available” for entrainment on a site-specific basis, taking into consideration an array of factors, including social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority. PNM is performing analyses to determine the potential costs of compliance with the rule. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. APS is currently in discussions with EPA Region 9, the National Pollutant Discharge Elimination System permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS has indicated that it does not expect such costs to be material.

Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants.  EPA’s proposal offers numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning waste operations.  The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits. Depending on which alternative EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. PNM has reviewed the proposed rule and continues to assess the potential impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. On April 9, 2014, several environmental groups agreed to allow EPA until September 30, 2015 to issue final effluent limits. Under the agreement, EPA will not seek any further extensions and will follow through on a separate agreement to issue a final rule on coal ash waste disposal by December 19, 2014. If EPA misses the December 19, 2014 deadline to issue a coal ash rule, then the agreement allows the environmental groups to require the EPA to issue the final effluent limits earlier. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. 

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of the former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM’s obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced similar results. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property.   This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels,  and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. It is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels.  Additional testing and analysis will need to be performed before conclusions can be reached regarding the cause of the increased nitrate levels or the method and cost of remediation.  PNM is unable to predict the outcome of these matters.

Coal Combustion Byproducts Waste Disposal

CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production.  Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office. 

In June 2010, EPA published a proposed rule that includes two options for waste designation of coal ash. One option is to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA’s proposal does not address the placement of CCBs in surface mine pits for reclamation. An OSM CCB rulemaking team has been formed to develop a proposed rule governing the placement of CCBs at coal mining and reclamation operations. 

On April 5, 2012, several environmental groups, including Sierra Club, filed a citizen suit in the D.C. Circuit claiming that EPA has failed to review and revise RCRA’s regulations with respect to CCBs. The groups allege that EPA has already determined that revisions to the CCBs regulations are necessary and that EPA now has a non-discretionary duty to revise the regulations. The environmental groups asked the court to direct EPA to complete its review of the regulation of CCBs and a hazardous waste analytical procedure and to issue necessary revisions of such regulations as soon as possible. Two industry group members subsequently filed separate lawsuits in the D.C. Circuit seeking to ensure that disposal of coal ash would not be regulated as a hazardous waste. The environmental and industry lawsuits have been consolidated. On January 29, 2014, EPA entered into a consent decree directing EPA to publish its final action regarding whether or not to pursue the proposed non-hazardous waste option for CCBs by December 19, 2014.

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

Hazardous Air Pollutants (“HAPs”) Rulemaking

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

Other Commitments and Contingencies

Coal Supply

The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At September 30, 2014 and December 31, 2013, prepayments for coal, which are included in other current assets, amounted to $26.1 million and $12.3 million. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement to supply processed coal for operation of SJGS through 2017. Under the coal sales agreement, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.

PNM and the other owners of SJGS are evaluating alternatives for the supply of coal after the expiration of the current coal sales agreement. As discussed under SJGS Ownership Restructuring Matters above, the Resolution and the non-binding term sheet approved by the SJGS Coordination Committee on June 26, 2014 recognize that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants will need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017. The remaining participants are in the process of negotiating agreements concerning future fuel supply for SJGS with SJCC and BHP. On October 1, 2014, the San Juan Fuels Committee approved a resolution authorizing an amendment to the coal sales agreement. The parties to the coal sales agreement and the amendment are SJCC, PNM, and Tucson. The amendment provides for the negotiation of a potential purchase transaction for the mine assets by one or more of the utilities, an affiliate, or another entity agreed to by the parties to be consummated on or before December 31, 2016. PNM anticipates that a consummated arrangement would ultimately involve a third-party mining company either as the owner of the mine or as a contract miner and could involve some or all of the remaining participants in SJGS. The amendment, which was effective as of October 2, 2014, also releases the parties from the obligation to negotiate an extension of the coal sales agreement, but does not impact the utilities’ option to purchase the mining assets at the end of the current contract term if the purchase transaction is not completed. On October 2, 2014, the parties also entered into an agreement that provides the SJGS participants with access to data necessary to evaluate the mine assets and liabilities. PNM cannot currently predict the outcome of these negotiations or if a transaction will be consummated.

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, expiring in 2031, was entered into with that entity. The BHP subsidiary is to be retained as the mine manager and operator until December 2016. Coal costs are anticipated to increase approximately 21% for the first full year of the new contract and will further increase over the contract term. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

In 2013, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. This estimate reflects that, with the proposed shutdown of SJGS Units 2 and 3 described above, the mine providing coal to SJGS will continue to operate through 2053, the anticipated life of SJGS. The 2013 estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new coal supply agreement. Based on the 2013 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $53.9 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of June 30, 2014. At September 30, 2014 and December 31, 2013, liabilities, in current dollars, of $22.9 million and $23.8 million for surface mine reclamation and $8.4 million and $7.8 million for underground mine reclamation were recorded in other deferred credits.

PNM collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from ratepayers for final reclamation of the surface mines at $100.0 million. Previously, PNM recorded a regulatory asset for the $100.0 million and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA discussed under The Clean Air Act – Regional Haze – SJGS above, an updated coal mine reclamation study was requested by the SJGS participants. As discussed under Coal Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant. The updated coal mine reclamation study indicates reclamation costs have increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, although the timing of payments will be delayed. The shutdown of Units 2 and 3 would reduce the amount of CCBs generated over the remaining life of SJGS, which could result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. How costs would be divided among the owners of SJGS has not been finalized. Regulatory determinations made by the NMPRC may also affect the impact on PNM. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

San Juan Underground Mine Fire Incident

On September 9, 2011, a fire was discovered at the underground mine owned and operated by SJCC that provides coal for SJGS. The federal Mine Safety and Health Administration (“MSHA”) was notified of the incident. On September 12, 2011, SJCC informed PNM that the fire was extinguished. However, MSHA required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. SJCC regained entry into the sealed area of the mine in early March 2012. At that time, MSHA conducted a root cause analysis inspection of the incident area, but has not yet issued its report. SJCC completed inspection of the mine equipment and reported no significant damage. SJCC removed the equipment from the impacted mine panel and reassembled it at a new panel face. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. Coal inventories have been restored to pre-incident levels and SJCC provided notice to PNM on September 23, 2014 that the mine has been restored to normal operations.

The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM included the portion of such costs allocable to its customers subject to New Mexico regulation in its FPPAC. PNM’s filings with the NMPRC reflected an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by between $17.4 million and $21.6 million. SJCC submitted an insurance claim regarding the costs it incurred due to the mine fire and informed PNM that it settled with its insurance carrier. PNM’s portion of the insurance recovery is $18.7 million. PNM has credited its FPPAC balancing account for the insurance proceeds allocable to PNM’s New Mexico jurisdictional customers. See Note 12.

Continuous Highwall Mining Royalty Rate

In August 2013, the DOI Bureau of Land Management (“BLM”) issued a proposed rulemaking that would retroactively apply the surface mining royalty rate of 12.5% to continuous highwall mining (“CHM”).  Comments regarding the rulemaking were due on October 11, 2013, and PNM submitted comments in opposition to the proposed rule. There is no legal deadline for adoption of the final rule.

SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS.  In March 2001, SJCC learned that the DOI Minerals Management Service (“MMS”) disagreed with the application of the underground royalty rate to CHM.  In August 2006, SJCC and MMS entered into a settlement agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal.  The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed.  PNM’s share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM’s FPPAC. PNM is unable to predict the outcome of this matter.

SJCC Arbitration

The coal supply agreement for SJGS provides that the participants in SJGS have the right to audit the costs billed by SJCC. An independent accounting firm has been engaged to perform audits of the costs billed under the provisions of the contract. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC. As provided in the contract, certain issues were submitted to a panel for binding arbitration. The issues were: 1) whether the SJGS participants owed SJCC unbilled mining costs of $5.2 million or whether SJCC owed the SJGS participants overbilled mining costs of $1.1 million, and 2) whether SJCC billed the SJGS participants $13.9 million as mining costs that SJCC should have considered to be capital costs, which were not billable under the mining contract.  PNM’s share of amounts subject to the arbitration are approximately 46.3%. A hearing before the arbitration panel on the remaining issues was held in May 2014. The arbitration panel found in favor of SJCC on both issues.  Of PNM’s share of the costs, approximately 33% of the first issue was passed through PNM’s FPPAC and the rest impacted earnings in the three months ended June 30, 2014. The amounts related to the second issue were recorded when billed in prior periods and had no impact in 2014.

Four Corners Severance Tax Assessment

On May 23, 2013, the New Mexico Taxation and Revenue Department (“NMTRD”) issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners. PNM’s share of any amounts paid related to this assessment would be approximately 8%, all of which would be passed through PNM’s FPPAC. For procedural reasons, on behalf of the Four Corners co-owners, including PNM, the coal supplier made a partial payment of the assessment and immediately filed a refund claim with respect to that partial payment in August 2013. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. PNM believes the assessment and the refund claim denial are without merit, but cannot predict the outcome of this matter.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.6 billion per occurrence. Commercial insurance carriers provide $375 million and $13.2 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential retrospective premium assessment per incident for all three units is $38.9 million, with a maximum annual payment limitation of $5.7 million.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). Effective April 1, 2014, a sublimit of $2.25 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium assessments of $4.8 million for each retrospective premium assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions.

Water Supply

Because of New Mexico’s arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Rio Bravo, Afton, Luna, and Lordsburg. Water availability is not an issue for these plants at this time. However, prolonged drought, ESA activities, and a Federal lawsuit by the State of Texas (suing the State of New Mexico over water allocations) could pose a threat of reduced water availability for these plants.

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

In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for forty years.

PVNGS Water Supply Litigation

In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows.

San Juan River Adjudication

In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo Nation’s water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees.  The court issued an order in August 2013 finding that no evidentiary hearing was warranted in the Navajo Nation proceeding, and on November 1, 2013 issued a Partial Final Judgment and Decree of the Water Rights of the Navajo Nation approving the proposed settlement with the Navajo Nation. Several parties filed a joint motion for a new trial, which was denied by the court. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM has entered its appearance in the appellate case. No hearing dates or deadlines have been set at this time.

PNM is participating in this proceeding since PNM’s water rights in the San Juan Basin may be affected by the rights recognized in the settlement agreement as being owned by the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin. PNM is unable to predict the ultimate outcome of this matter or estimate the amount or range of potential loss and cannot determine the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. Final resolution of the case cannot be expected for several years. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

Rights-of-Way Matter

On January 28, 2014, the County Commission of Bernalillo County, New Mexico passed an ordinance requiring utilities to enter into a use agreement and pay a yet to be determined fee as a condition to installing, maintaining, and operating facilities on county rights-of-way. The fee is purported to compensate the county for costs of administering, maintaining, and capital improvements to the rights-of-way. On February 27, 2014, PNM and other utilities filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. In June 2014, the utilities and Bernalillo County reached an agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement.  The federal court ruled in favor of Bernalillo County, dismissing the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. If the challenges to the ordinance are unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.

Complaint Against Southwestern Public Service Company

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

Navajo Nation Allottee Matters

A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both.  In March 2010, the court ordered that the entirety of the plaintiffs’ case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court.  In May 2010, plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (“BIA”), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director’s decision to the DOI, Office of Hearings and Appeals, Interior Board of Indian Appeals. Following briefing on the merits, on August 20, 2013, that board issued a decision upholding the Regional Director’s decision that the allottees had failed to perfect their appeals, and dismissed the allottees’ appeals, without prejudice.  The allottees have not refiled their appeals. Although this matter was dismissed without prejudice, PNM considers the matter concluded. However, PNM continues to monitor this matter in order to preserve its interests regarding any PNM-acquired rights-of-way.

In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice.  On April 2, 2014, the allotees’ appeal was dismissed with prejudice concluding this matter. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments.  PNM is in the process of investigating the validity of this notice of revocation and its potential impact in light of the BIA’s position and the recent dismissal with prejudice of the appeal, and is therefore unable at this time to predict the likely outcome of this matter.

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Fair Value of Derivative and Other Financial Instruments

9 Months Ended

Sep. 30, 2014

Fair Value of Derivative and Other Financial Instruments [Abstract]

Fair Value of Derivative and Other Financial Instruments

Fair Value of Derivative and Other Financial Instruments

Energy Related Derivative Contracts

Overview

The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. The Company’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. Additional information concerning the Company’s energy related derivative contracts, including how commodity risk is managed, is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Commodity Risk

Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.

Accounting for Derivatives

Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. Energy contracts that meet the definition of a derivative under GAAP and do not qualify, or are not designated, for the normal purchases and normal sales exception are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met and elected. Normal purchases and normal sales are not marked to market and are reflected in results of operations when the underlying transactions settle.

During the nine months ended September 30, 2014 and the year ended December 31, 2013, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. The Company has no trading transactions.

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

Commodity Derivatives

Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows:

	Economic Hedges
	September 30, 2014			December 31, 2013
PNMR and PNM	(In thousands)
Current assets	$	4,148		$	4,064
Deferred charges	1,084			3,002
	5,232			7,066
Current liabilities	(1,370		)	(2,699		)
Long-term liabilities	(688		)	(1,094		)
	(2,058		)	(3,793		)
Net	$	3,174		$	3,273

Included in the above table are $3.0 million of current assets and $0.8 million of deferred charges at September 30, 2014 and $3.0 million of current assets and $3.0 million of deferred charges at December 31, 2013 related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at September 30, 2014 and December 31, 2013.

At September 30, 2014 and December 31, 2013, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at September 30, 2014 and December 31, 2013, amounts posted as cash collateral under margin arrangements were $2.4 million and $2.8 million for both PNMR and PNM. PNMR and PNM had obligations to return cash collateral of $0.2 million at September 30, 2014 and $0.2 million at December 31, 2013. Cash collateral amounts are included in other current assets and other current liabilities on the Condensed Consolidated Balance Sheets.

PNM has a NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.2 million of current assets and $0.1 million of current liabilities at September 30, 2014 and $0.4 million of current assets and $0.1 million of current liabilities at December 31, 2013 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.

The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.

	Economic Hedges
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
PNMR and PNM	(In thousands)
Electric operating revenues	$	2,352		$	7,077		$	(2,124	)	$	5,743
Cost of energy	(60		)	(72		)	186			421
Total gain (loss)	$	2,292		$	7,005		$	(1,938	)	$	6,164

Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:

	Economic Hedges
	MMBTU	MWh
September 30, 2014
PNMR and PNM	656,000	(2,511,371	)
December 31, 2013
PNMR and PNM	905,000	(3,343,783	)

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

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

Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
September 30, 2014
PNMR and PNM	$	1,532	$	—	$	1,403
December 31, 2013
PNMR and PNM	$	2,398	$	—	$	2,152

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not included in retail rates, that unit’s power is being sold in the wholesale market. Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of September 30, 2014, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium.  PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales through the end of 2014 through hedging arrangements that are accounted for as economic hedges. PNM is also partially hedged for 2015.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and a trust for PNM’s share of post-term reclamation costs related to the coal mines that serve SJGS (Note 11). The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table. At September 30, 2014 and December 31, 2013, the fair value of available-for-sale securities included $231.4 million and $222.5 million for the NDT and $4.5 million and $4.4 million for the mine reclamation trust.

	September 30, 2014				December 31, 2013
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,338	$	—	$	3,356
Equity securities:
Domestic value	15,360		41,917		14,523		39,460
Domestic growth	18,452		74,647		25,656		76,292
International and other	1,339		16,957		1,040		16,633
Fixed income securities:
U.S. Government	520		19,616		158		21,941
Municipals	4,970		67,595		1,018		58,568
Corporate and other	631		11,824		207		10,605
	$	41,272	$	235,894	$	42,602	$	226,855

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold and reflect impairments.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(In thousands)
Proceeds from sales	$	29,103		$	103,230		$	82,222		$	179,336
Gross realized gains	$	3,134		$	2,719		$	11,616		$	8,962
Gross realized (losses)	$	(2,172	)	$	(531	)	$	(3,382	)	$	(2,027	)

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

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

At September 30, 2014, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR		PNM
	(In thousands)
Within 1 year	$	3,601	$	7,994	$	7,994
After 1 year through 5 years	20,886		25,456		24,718
After 5 years through 10 years	11,561		—		—
After 10 years through 15 years	9,549		—		—
After 15 years through 20 years	11,313		—		—
After 20 years	42,125		—		—
	$	99,035	$	33,450	$	32,712

Fair Value Disclosures

The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models.

For available-for-sale securities, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For the Company’s long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and certain items in other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar types of assets and liabilities. Management of the Company independently verifies the information provided by pricing services.

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at September 30, 2014 and December 31, 2013 for items recorded at fair value.

				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2014	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,338		$	3,338	$	—
Equity securities:
Domestic value	41,917			41,917		—
Domestic growth	74,647			74,647		—
International and other	16,957			16,957		—
Fixed income securities:
U.S. Government	19,616			17,865		1,751
Municipals	67,595			—		67,595
Corporate and other	11,824			2,544		9,280
	$	235,894		$	157,268	$	78,626
Commodity derivative assets	$	5,232		$	—	$	5,232
Commodity derivative liabilities	(2,058		)	—		(2,058		)
Net	$	3,174		$	—	$	3,174
December 31, 2013
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,356		$	3,356	$	—
Equity securities:
Domestic value	39,460			39,460		—
Domestic growth	76,292			76,292		—
International and other	16,633			16,633		—
Fixed income securities:
U.S. Government	21,941			20,194		1,747
Municipals	58,568			—		58,568
Corporate and other	10,605			2,245		8,360
	$	226,855		$	158,180	$	68,675
Commodity derivative assets	$	7,066		$	—	$	7,066
Commodity derivative liabilities	(3,793		)	—		(3,793		)
Net	$	3,273		$	—	$	3,273

The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:

					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
September 30, 2014	(In thousands)
PNMR
Long-term debt	$	1,875,172	$	2,072,872	$	—	$	2,072,872	$	—
Investment in PVNGS lessor notes	$	31,469	$	32,712	$	—	$	—	$	32,712
Other investments	$	1,667	$	2,406	$	546	$	—	$	1,860
PNM
Long-term debt	$	1,390,647	$	1,525,625	$	—	$	1,525,625	$	—
Investment in PVNGS lessor notes	$	31,469	$	32,712	$	—	$	—	$	32,712
Other investments	$	300	$	300	$	300	$	—	$	—
TNMP
Long-term debt	$	365,759	$	422,583	$	—	$	422,583	$	—
Other investments	$	245	$	245	$	245	$	—	$	—
December 31, 2013
PNMR
Long-term debt	$	1,745,420	$	1,905,230	$	—	$	1,905,230	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279
Other investments	$	1,835	$	3,196	$	690	$	—	$	2,506
PNM
Long-term debt	$	1,290,618	$	1,382,938	$	—	$	1,382,938	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279
Other investments	$	445	$	445	$	445	$	—	$	—
TNMP
Long-term debt	$	336,036	$	390,814	$	—	$	390,814	$	—
Other investments	$	245	$	245	$	245	$	—	$	—

The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the nine months ended September 30, 2014 and the year ended December 31, 2013.

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Variable Interest Entities

9 Months Ended

Sep. 30, 2014

Variable Interest Entities [Abstract]

Variable Interest Entities; Acquisition

Variable Interest Entities; Acquisition

GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. Additional information concerning PNM’s variable interest entities is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Valencia

PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and nine months ended September 30, 2014, PNM paid $4.8 million and $14.4 million for fixed charges and $0.3 million and $1.0 million for variable charges. For the three and nine months ended September 30, 2013, PNM paid $4.8 million and $14.1 million for fixed charges and $0.7 million and $1.0 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM has concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates the entity in its financial statements. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Operating revenues	$	5,061		$	5,453		$	15,300		$	15,150
Operating expenses	(1,360		)	(1,326		)	(4,160		)	(4,246		)
Earnings attributable to non-controlling interest	$	3,701		$	4,127		$	11,140		$	10,904

Financial Position

	September 30,		December 31,
	2014		2013
	(In thousands)
Current assets	$	3,435	$	2,658
Net property, plant, and equipment	73,024		75,137
Total assets	76,459		77,795
Current liabilities	1,039		766
Owners’ equity – non-controlling interest	$	75,420	$	77,029

During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity. The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process was initiated since the parties failed to reach agreement on fair market value within 60 days. Under the PPA, results of the appraisal process established the purchase price, after which PNM was to determine, in its sole discretion, whether or not to exercise its option to purchase the 50% interest. The PPA also provides that the purchase price may be adjusted to reflect the period between the determination of the purchase price and the closing. The appraisal process determined the purchase price as of October 8, 2013 to be $85.0 million, prior to any adjustment to reflect the period through the closing date. Approval of the purchase by the NMPRC and FERC would be required, which process could take in excess of 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. PNM is discussing these issues with the owner of Valencia. PNM cannot predict whether or not it will reach agreement with the owner of Valencia, if required regulatory and other approvals will be received, or if the purchase will be completed.

PVNGS Leases

PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. PNM is not the legal or tax owner of the leased assets. The leases provide PNM with an option to purchase the leased assets at appraised value at the end of the leases. PNM does not have a fixed price purchase option and does not provide residual value guarantees. The leases also provide PNM with options to renew the leases at fixed rates set forth in the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K and Note 6, for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities.

PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments. As of September 30, 2014, these payments aggregate $20.3 million, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, over the remaining original terms of the leases and $145.2 million during the renewal terms of the leases that PNM elected to renew. Under certain circumstances (for example, final shutdown of the plant, the NRC issuing specified violation orders with respect to PVNGS, or the occurrence of specified nuclear events), PNM would be required to make specified payments to the beneficial owners and take title to the leased interests. If such an event had occurred as of September 30, 2014, PNM could have been required to pay the beneficial owners up to $123.8 million, which would result in PNM taking ownership of the leased assets and termination of the leases. Other than as discussed in Note 6, PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets.

PNM has evaluated the PVNGS lease arrangements, including the notices, amendments, and agreements referred to above, and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP. PNM has recorded no assets or liabilities related to the trusts other than the accrual of lease payments between the scheduled payment dates, which were $11.8 million at September 30, 2014 and $26.0 million at December 31, 2013, that are included in other current liabilities on the Condensed Consolidated Balance Sheets.

Rio Bravo, formerly known as Delta

PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which was a variable interest under GAAP. PNM also controlled the dispatch of the generating plant, which impacted the variable payments made under the PPA and impacted the economic performance of the entity that owned Delta. This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it was the primary beneficiary of the entity that owned Delta, or to consolidate that entity if it were determined that PNM was the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.

In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owned Delta. FERC approved the purchase on February 26, 2013 and the NMPRC approved the purchase on June 26, 2013. Closing was subject to the seller remedying specified operational, NERC compliance, and environmental issues, as well as other customary closing conditions. PNM closed on the purchase on July 17, 2014 and recorded the purchase as of that date. At closing, PNM made a cash payment of $22.8 million, which reflected an adjustment for working capital compared to a targeted working capital and included amounts placed in escrow. Delta had project financing debt, which PNM retired at closing of the purchase, amounting to $14.6 million at closing. Subsequent to closing, PNM changed the name of the facility to Rio Bravo.

PNM recorded the acquisition as a business combination and reflected the requirements of the FERC Uniform System of Accounts since the purchased assets are subject to traditional rate regulation by the NMPRC and FERC. Accordingly, as of the acquisition date, PNM recorded plant in service of $58.1 million and accumulated depreciation of $23.5 million, reflecting the original cost of the facilities and the estimated economic life to PNM. PNM also recorded current assets of $3.6 million, deferred charges of $3.4 million, current liabilities of $0.3 million, and non-current regulatory liabilities of $3.4 million.

PNM made fixed and variable payments to Delta under the PPA. For the periods from July 1, 2014 through July 17, 2014 and January 1, 2014 through July 17, 2014, PNM incurred fixed capacity charges of $0.3 million and $3.5 million and variable energy charges of $0.1 million and $0.6 million under the PPA. For the three and nine months ended September 30, 2013, PNM incurred fixed capacity charges of $1.6 million and $4.8 million and variable energy charges of $0.7 million and $1.3 million. PNM recovered the variable energy charges through its FPPAC.

PNM began consolidating Rio Bravo at the date of the acquisition. Prior to the acquisition, consolidation of Delta would have been immaterial to the Condensed Consolidated Balance Sheets of PNMR and PNM. Since all of Delta’s revenues and expenses were attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Condensed Consolidated Statements of Earnings of PNMR and PNM would have been to reclassify Delta’s net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM.

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Lease Commitments

9 Months Ended

Sep. 30, 2014

Leases [Abstract]

Lease Commitments

Lease Commitments

The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS and an interest in the EIP transmission line. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. Each of the leases provides PNM with an option to purchase the leased assets at fair market value at the end of the lease. In addition, the leases provide PNM with options to renew the leases at fixed rates set forth in each of the leases for two years beyond the termination of the original lease terms. The option periods on certain leases could be further extended for up to an additional six years (the “Maximum Option Period”) if the appraised remaining useful lives and fair values of the leased assets are greater than parameters set forth in the leases. The rental payments during the renewal option periods would be 50% of the amounts during the original terms of the leases.

Following procedures set forth in the PVNGS leases, PNM notified each of the lessors under the Unit 1 leases that it would elect to renew those leases for the Maximum Option Period on the expiration date of the original leases. In addition, PNM notified the lessor under the one Unit 2 lease containing the Maximum Option Period provision that it would elect to renew that lease for the Maximum Option Period on the expiration date of the original lease. On December 11, 2013, PNM and each of the Unit 1 lessors entered into amendments to each of the Unit 1 leases setting forth the terms and conditions that will implement the extension of the term of the lease through the agreed upon Maximum Option Period expiring on January 15, 2023. Similarly, on March 18, 2014, PNM and the lessor under the one Unit 2 lease containing the Maximum Option Period provision entered into an amendment to that lease setting forth the terms and conditions that will implement the extension of the term of the lease through the agreed upon Maximum Option Period expiring on January 15, 2024.

For the three PVNGS Unit 2 leases which do not contain the Maximum Option Period provisions, PNM, following procedures set forth in the leases, notified each of the lessors that PNM would elect to purchase the assets underlying those leases on the expiration date of the original leases. On February 25, 2014, PNM and the lessor under one of the Unit 2 leases entered into a letter agreement that establishes that the purchase price, representing the fair market value, to be paid by PNM for the assets underlying that lease will be $78.1 million on January 15, 2016. This lease is for 31.25 MW of the entitlement from PVNGS Unit 2. The lease remains in existence and PNM will record the purchase at the termination of the lease on January 15, 2016.

On May 1, 2014, PNM and the trusts that are the lessors under the other two PVNGS Unit 2 leases signed a letter agreement that establishes a binding agreement regarding the purchase price, representing the fair market value, to be paid by PNM for the assets underlying those leases of $85.2 million on January 15, 2016. These leases are for 32.76 MW of the entitlement from PVNGS Unit 2. PNMR Development, a wholly-owned subsidiary of PNMR, is also a party to the letter agreement, which constitutes a letter of intent providing PNMR Development with the option, subject to approval by the Board and negotiation of definitive documents, to acquire the entities that own the leased assets at any time from June 1, 2014 through January 14, 2016. The early purchase price would be equal to the January 15, 2016 purchase price discounted to the actual purchase date. The early purchase amount was $79.9 million on June 1, 2014 and escalates to $85.2 million on January 14, 2016. The consideration paid to the lessor on an early purchase would include an additional amount equal to the discounted value of the lessors’ equity return portion of the future lease payments. Such additional consideration was $5.8 million on June 1, 2014 and declines to $1.2 million on January 14, 2016. PNMR and PNM are unable to predict whether or not the early purchase will occur.

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2014

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

Stock-Based Compensation

Stock-Based Compensation

PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets and some of these awards also have time vesting requirements. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 13 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, the awards vest ratably over three years from the grant date of the award. However, certain awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards.

The stock-based compensation expense related to stock options and restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However, compensation expense for awards to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for performance-based shares is recognized ratably over the performance period and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At September 30, 2014 and December 31, 2013, PNMR had unrecognized expense related to stock awards of $7.9 million and $4.6 million. 

The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period.

The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:

	Nine Months Ended September 30,
Restricted Shares and Performance Based Shares	2014			2013
Expected quarterly dividends per share	$	0.185		$	0.165
Risk-free interest rate	0.62		%	0.34		%
Market-Based Shares
Dividend yield	2.82		%	2.86		%
Expected volatility	25.11		%	25.11		%
Risk-free interest rate	0.64		%	0.36		%

The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the nine months endedSeptember 30, 2014:

	Stock Option Shares		Weighted- Average Exercise Price		Restricted Stock		Weighted- Average Grant Date Fair Value
Outstanding at beginning of period	1,343,666		$	20.63	315,305		$	17.87
Granted	—		$	—	242,164		$	21.27
Exercised	(287,075	)	$	19.00	(295,423	)	$	16.68
Forfeited	(38,534	)	$	27.59	(515	)	$	24.74
Expired	(17,151	)	$	26.43	—		$	—
Outstanding at end of period	1,000,906		$	20.73	261,531		$	22.31

Included as restricted stock granted and exercised in the table above are 112,864 shares that were based upon achieving performance or market targets for 2013. The Board approved these shares in February 2014 (based upon achieving market targets, weighted at 60%, at maximum levels, and performance targets, weighted at 40%, at below threshold levels for the 2011 through 2013 performance period).

PNMR’s stock-based compensation program provides for performance or market targets through 2016. Excluded from the above table are maximums of 198,369, 179,811, and 175,735 restricted stock shares for periods ending in 2014, 2015, and 2016 that would be awarded if all performance or market criteria are achieved and all executives remain eligible.

In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR’s common stock if the Company meets specific market targets at the end of 2016 and she remains an employee of the Company. If the Company achieves specific market targets at the end of 2014 and, with certain exceptions, she remains an employee of the Company, she would receive 35,000 of the total shares at that time. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include any restricted stock shares under the retention award agreement.

At September 30, 2014, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.2 million with a weighted-average remaining contract life of 2.98 years. At September 30, 2014, the exercise price of 435,472 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

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

	Nine Months Ended September 30,
Stock Options	2014		2013
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	625
Total intrinsic value of options exercised (in thousands)	$	2,199	$	2,466
Restricted Stock
Weighted-average grant date fair value	$	21.27	$	20.03
Total fair value of restricted shares that vested (in thousands)	$	4,929	$	4,395

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Significant Accounting Policies and Responsibility for Financial Statements Significant Accounting Policies and Responsibility for Financial Statements (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Dividends on Common Stock [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.185	$ 0.185	$ 0.165	$ 0.165	$ 0.555	$ 0.495
Dividends, Common Stock, Cash					$ 44,208
Public Service Company of New Mexico [Member]
Dividends on Common Stock [Line Items]
Dividends, Common Stock, Cash					30,300	68,000
Texas-New Mexico Power Company [Member]
Dividends on Common Stock [Line Items]
Dividends, Common Stock, Cash					$ 16,300	$ 3,700

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Commitments and Contingencies (Other Commitments and Contingencies) (Details) (USD $)																			9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 NMTRD Coal Severance Tax [Member] Four Corners [Member]	Sep. 30, 2014 San Juan Generating Station [Member] Continuous Highwall Mining [Member]	Sep. 30, 2014 San Juan Generating Station [Member] SJCC Arbitration [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Nuclear Plant [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Nuclear Plant [Member] Commercial Providers [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Nuclear Plant [Member] Industry Wide Retrospective Assessment Program [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Maximum [Member] Nuclear Plant [Member]	Apr. 01, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Maximum [Member] Nuclear Plant [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] San Juan Underground Mine Fire [Member] Fuel and Purchased Power Adjustment Clause [Member] San Juan Generating Station [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] San Juan Underground Mine Fire [Member] Fuel and Purchased Power Adjustment Clause [Member] San Juan Generating Station [Member] Minimum [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] San Juan Underground Mine Fire [Member] Fuel and Purchased Power Adjustment Clause [Member] San Juan Generating Station [Member] Maximum [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] NMTRD Coal Severance Tax [Member] Four Corners [Member]	Apr. 02, 2014 Public Service Company of New Mexico [Member] Navajo Nation Allottee Matters [Member] Allotment_Parcel	Jan. 06, 2014 Public Service Company of New Mexico [Member] Navajo Nation Allottee Matters [Member] Allotment_Parcel	Sep. 01, 2012 Public Service Company of New Mexico [Member] Navajo Nation Allottee Matters [Member] Allotment_Parcel	Sep. 30, 2014 Public Service Company of New Mexico [Member] Surface [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member] San Juan Generating Station [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Underground [Member] Loss on Long-term Purchase Commitment [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Underground [Member] Loss on Long-term Purchase Commitment [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Underground [Member] Loss on Long-term Purchase Commitment [Member] San Juan Generating Station [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Coal Supply [Member] San Juan Generating Station [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Coal Supply [Member] San Juan Generating Station [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] SJCC Arbitration [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Other Assets, Current	$ 55,277,000	$ 34,590,000																							$ 26,100,000	$ 12,300,000
Public Utilities, Estimated Increase in Coal Cost, Percentage																									21.00%
Loss Contingency, Estimate of Possible Loss																					53,900,000			93,300,000
Loss Contingency Accrual																			22,900,000	23,800,000		8,400,000	7,800,000
Final Reclamation, capped amount to be collected																			100,000,000
Regulatory Assets																		100,000,000
Estimated increased coal costs and deferral of cost recovery												17,400,000	21,600,000
Public Utilities, Insurance Recovery											18,700,000
Public Utilities, Proposed Retroactive Surface Mining Royalty Rate				12.50%
Public Utilities, Current Surface Mining Royalty Rate applied between 2000 and 2003				8.00%
Public Utilities, Estimated Underpaid Surface Mining Royalties under proposed rate change				5,000,000
Public Utilities, PNM Share Estimated Underpaid Surface Mining Royalties under proposed rate change				46.30%
Public Utilities, Potential Unbilled Mining Costs Owed to SJCC					5,200,000
Public Utilities, Potential Overbilled Mining Costs SJCC Owes to SJGS Owners					1,100,000
Public Utilities, Potential Capital Improvements billed as Mining Costs to SJGS Owners					13,900,000
Public Utilities, PNM Share of arbitration ruling																											46.30%
Public Utilities, FFPAC Percentage of mining costs overbilled or unbilled ruled by arbitration																											33.00%
Public Utilities, Assessed Coal Severance Surtax Penalty and Interest			30,000,000
Public Utilities, PNM Share Assessed Coal Severance Surtax Penalty and Interest to pass through FFPAC														8.00%
Public Utilities, Liability Insurance Coverage							375,000,000	13,200,000,000	13,600,000,000
Public Utilities, Ownership Percentage in Nuclear Reactor						10.20%
Public Utilities, Maximum Potential Assessment Per Incident						38,900,000
Public Utilities, Annual Payment Limitation Related to Incident						5,700,000
Public Utilities, Aggregate Amount of All Risk Insurance						2,750,000,000
Public Utilities, Liability Insurance Coverage Sublimit										2,250,000,000
Public Utilities, Maximum Amount under Nuclear Electric Insurance Limited						$ 4,800,000
Number of landowners claiming to be Navajo allottees																	43
Number of allotment parcels' appraisal requested for review																58
Number of allotments where landowners are revoking rights of way renewal consents															6

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Income Taxes

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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

On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction will be phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment, which was in three months ended June 30, 2013. At that time, the portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The increase in the regulatory liability was $23.9 million. In addition, the portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax expense of $1.2 million during the three months ended June 30, 2013. Changes in the estimated timing of reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2014, PNM’s regulatory liability was reduced by $4.6 million, which increased deferred tax liabilities. Additionally, deferred tax assets not related to PNM’s regulatory activities were reduced by $0.2 million, which increased income tax expense in the Corporate and Other segment.

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

In 2013, the FASB issued Accounting Standards Update 2013-11, which requires entities to present liabilities for uncertain tax positions as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such carryforward could be used to offset those liabilities upon settlement.  The update was required to be applied prospectively for periods beginning after December 15, 2013, and early adoption was permitted.  The Company elected not to adopt the change for 2013, but did adopt it for 2014 as required by the update.  Had the Company applied the update at December 31, 2013, the effect would have been decreases in net operating loss deferred tax assets of $19.9 million for PNMR, $11.2 million for PNM, and $6.8 million for TNMP, along with the elimination of the corresponding assets and liabilities associated with uncertain tax positions. There was no impact to earning from adopting the update.

In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008 resulting in years prior to 2009 being closed to examination by federal taxing authorities. As a result of the settlement, the Company received net federal tax refunds of $2.0 million. The IRS examination resulted in the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. The settlement of the IRS examination, including the uncertain tax position matters, resulted in PNMR recording an income tax benefit of $0.2 million on a consolidated basis in the three months ended June 30, 2014. PNM recorded an income tax expense of $1.1 million, TNMP reflected no impact, and an income tax benefit of $1.3 million was recorded in PNMR’s Corporate and Other segment. After the settlements, the liabilities related to uncertain tax positions for PNMR, PNM, and TNMP were $14.3 million, $11.5 million, and none.

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

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

PNMR SEGMENT INFORMATION

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2014
Electric operating revenues	$	334,993		$	78,958		$	—		$	413,951
Cost of energy	115,097			17,402			—			132,499
Margin	219,896			61,556			—			281,452
Other operating expenses	101,757			22,251			(3,650		)	120,358
Depreciation and amortization	27,524			13,432			3,339			44,295
Operating income	90,615			25,873			311			116,799
Interest income	2,102			—			(18		)	2,084
Other income (deductions)	1,569			793			(589		)	1,773
Net interest charges	(20,092		)	(6,870		)	(3,153		)	(30,115		)
Segment earnings (loss) before income taxes	74,194			19,796			(3,449		)	90,541
Income taxes (benefit)	25,142			7,441			(1,528		)	31,055
Segment earnings (loss)	49,052			12,355			(1,921		)	59,486
Valencia non-controlling interest	(3,701		)	—			—			(3,701		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	45,219		$	12,355		$	(1,921	)	$	55,653
Nine Months Ended September 30, 2014
Electric operating revenues	$	873,434		$	215,574		$	—		$	1,089,008
Cost of energy	304,365			50,167			—			354,532
Margin	569,069			165,407			—			734,476
Other operating expenses	315,714			63,732			(10,243		)	369,203
Depreciation and amortization	81,629			37,276			9,519			128,424
Operating income	171,726			64,399			724			236,849
Interest income	6,295			—			(54		)	6,241
Other income (deductions)	8,749			1,495			(1,547		)	8,697
Net interest charges	(59,927		)	(20,122		)	(9,572		)	(89,621		)
Segment earnings (loss) before income taxes	126,843			45,772			(10,449		)	162,166
Income taxes (benefit)	42,331			17,081			(6,044		)	53,368
Segment earnings (loss)	84,512			28,691			(4,405		)	108,798
Valencia non-controlling interest	(11,140		)	—			—			(11,140		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	72,976		$	28,691		$	(4,405	)	$	97,262
At September 30, 2014:
Total Assets	$	4,358,474		$	1,216,545		$	134,190		$	5,709,209
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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

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Pension and Other Postretirement Benefit Plans (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension liability, Estimated percentage increase due to change in assumptions	7.00%		7.00%
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$ 0	$ 0	$ 0	$ 0
Interest cost	7,541,000	7,035,000	22,622,000	21,106,000
Expected return on plan assets	(9,511,000)	(10,482,000)	(28,533,000)	(31,447,000)
Amortization of net (gain) loss	3,255,000	3,710,000	9,765,000	11,130,000
Amortization of prior service cost	(241,000)	19,000	(724,000)	57,000
Net Periodic Benefit Cost (Income)	1,044,000	282,000	3,130,000	846,000
Defined Benefit Plan, Contributions by Employer		0		60,000,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	50,000,000		50,000,000
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)			4.50%
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)			5.30%
Public Service Company of New Mexico [Member] | OPEB [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	45,000	65,000	136,000	195,000
Interest cost	1,159,000	1,029,000	3,473,000	3,085,000
Expected return on plan assets	(1,410,000)	(1,261,000)	(4,229,000)	(3,782,000)
Amortization of net (gain) loss	556,000	1,061,000	1,669,000	3,182,000
Amortization of prior service cost	(336,000)	(336,000)	(1,008,000)	(1,008,000)
Net Periodic Benefit Cost (Income)	14,000	558,000	41,000	1,672,000
Defined Benefit Plan, Contributions by Employer	800,000	800,000	2,400,000	2,400,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	14,000,000		14,000,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	3,300,000		3,300,000
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	205,000	180,000	616,000	540,000
Expected return on plan assets	0	0	0	0
Amortization of net (gain) loss	52,000	58,000	157,000	174,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	257,000	238,000	773,000	714,000
Defined Benefit Plan, Contributions by Employer	400,000	400,000	1,200,000	1,100,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	1,600,000		1,600,000
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	798,000	772,000	2,395,000	2,315,000
Expected return on plan assets	(1,132,000)	(1,212,000)	(3,395,000)	(3,637,000)
Amortization of net (gain) loss	166,000	262,000	499,000	787,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	(168,000)	(178,000)	(501,000)	(535,000)
Defined Benefit Plan, Contributions by Employer		0		1,000,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	0		0
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)	4.50%
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)	5.30%
Texas-New Mexico Power Company [Member] | OPEB [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	59,000	75,000	178,000	225,000
Interest cost	155,000	141,000	464,000	424,000
Expected return on plan assets	(133,000)	(126,000)	(400,000)	(377,000)
Amortization of net (gain) loss	(31,000)	0	(92,000)	0
Amortization of prior service cost	8,000	14,000	24,000	43,000
Net Periodic Benefit Cost (Income)	58,000	104,000	174,000	315,000
Defined Benefit Plan, Contributions by Employer	0	0	300,000	300,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	1,400,000		1,400,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	300,000		300,000
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	10,000	9,000	29,000	27,000
Expected return on plan assets	0	0	0	0
Amortization of net (gain) loss	0	0	0	0
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	10,000	9,000	29,000	27,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	100,000		100,000
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Contributions by Employer	$ 100,000	$ 100,000	$ 100,000	$ 100,000

XML

Fair Value of Derivative and Other Financial Instruments, Statement of Earnings Information (Details) (PNMR and PNM [Member], Commodity Contract [Member], Fair Value Hedging [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 2,292	$ 7,005	$ (1,938)	$ 6,164
Electric operating revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	2,352	7,077	(2,124)	5,743
Cost of energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ (60)	$ (72)	$ 186	$ 421

XML

Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash Flows From Operating Activities:
Net Earnings	$ 108,798	$ 104,159
Net earnings	97,262	92,859
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	157,687	157,856
Deferred income tax expense	55,553	57,878
Net unrealized (gains) on commodity derivatives	(67)	(5,858)
Realized (gains) on available-for-sale securities	(8,234)	(6,935)
Stock based compensation expense	4,680	4,315
Regulatory disallowances	0	1,735
Other, net	(642)	1,384
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(22,158)	(23,731)
Materials, supplies, and fuel stock	5,494	(724)
Other current assets	(19,816)	(6,667)
Other assets	30,502	21,656
Accounts payable	79	(17,786)
Accrued interest and taxes	32,488	126,218
Other current liabilities	(21,197)	(32,111)
Other liabilities	3,074	(70,379)
Net cash flows from operating activities	326,241	311,010
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(293,361)	(233,928)
Proceeds from sales of available-for-sale securities	82,222	179,336
Purchases of available-for-sale securities	(81,644)	(181,423)
Return of principal on PVNGS lessor notes	20,758	23,357
Purchase of Rio Bravo	(36,235)	0
Other, net	(3,433)	1,232
Net cash flows from investing activities	(311,693)	(211,426)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(49,200)	(46,700)
Long-term borrowings	255,000	75,000
Repayment of long-term debt	(125,000)	(26,037)
Cash paid in debt exchange	0	(13,048)
Proceeds from stock option exercise	5,495	3,500
Awards of common stock	(15,573)	(12,429)
Dividends paid	(44,600)	(38,233)
Valencia’s transactions with its owner	(12,749)	(13,477)
Other, net	(2,030)	(3,706)
Net cash flows from financing activities	11,343	(75,130)
Change in Cash and Cash Equivalents	25,891	24,454
Cash and Cash Equivalents at Beginning of Period	2,533	8,985
Cash and Cash Equivalents at End of Period	28,424	33,439
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	60,075	63,985
Income taxes paid (refunded), net	(2,529)	(95,472)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	(6,674)	2,535
Premium on long-term debt incurred in connection with debt exchange	0	36,297
Pnm Electric [Member]
Cash Flows From Operating Activities:
Net Earnings	84,512	96,420
Net earnings	73,372	85,516
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	108,069	104,161
Deferred income tax expense	45,313	49,870
Net unrealized (gains) on commodity derivatives	(67)	(5,858)
Realized (gains) on available-for-sale securities	(8,234)	(6,935)
Regulatory disallowances	0	1,735
Other, net	(355)	(1,342)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(16,782)	(14,123)
Materials, supplies, and fuel stock	5,697	(744)
Other current assets	(20,806)	(5,187)
Other assets	29,796	21,977
Accounts payable	10,100	(4,953)
Accrued interest and taxes	19,984	66,090
Other current liabilities	(21,586)	(43,935)
Other liabilities	2,841	(67,062)
Net cash flows from operating activities	238,482	190,114
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(199,771)	(164,669)
Proceeds from sales of available-for-sale securities	82,222	179,336
Purchases of available-for-sale securities	(81,644)	(181,423)
Return of principal on PVNGS lessor notes	20,758	23,357
Purchase of Rio Bravo	(36,235)	0
Other, net	(3,404)	1,234
Net cash flows from investing activities	(218,074)	(142,165)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(49,200)	(21,100)
Short-term borrowings (repayments), affiliate, net	(26,000)	0
Long-term borrowings	175,000	75,000
Repayment of long-term debt	(75,000)	0
Dividends paid	(30,659)	(68,424)
Valencia’s transactions with its owner	(12,749)	(13,477)
Other, net	(1,196)	(1,727)
Net cash flows from financing activities	(19,804)	(29,728)
Change in Cash and Cash Equivalents	604	18,221
Cash and Cash Equivalents at Beginning of Period	21	3,958
Cash and Cash Equivalents at End of Period	625	22,179
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	41,606	42,145
Income taxes paid (refunded), net	(215)	(44,999)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	(10,586)	8,912
Tnmp Electric [Member]
Cash Flows From Operating Activities:
Net Earnings	28,691	22,170
Net earnings	28,691	22,170
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	39,577	40,946
Deferred income tax expense	4,256	3,901
Other, net	(169)	(13)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(5,376)	(9,608)
Materials, supplies, and fuel stock	(203)	20
Other current assets	1,761	(2,420)
Other assets	(58)	36
Accounts payable	(1,302)	(291)
Accrued interest and taxes	19,054	14,669
Other current liabilities	(1,217)	(1,946)
Other liabilities	1,397	2,182
Net cash flows from operating activities	86,411	69,646
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(88,940)	(67,400)
Net cash flows from investing activities	(88,940)	(67,400)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	0	12,000
Short-term borrowings (repayments), affiliate, net	(10,300)	4,800
Long-term borrowings	80,000	0
Repayment of long-term debt	(50,000)	0
Cash paid in debt exchange	0	(13,048)
Dividends paid	(16,336)	(3,726)
Other, net	(835)	(2,117)
Net cash flows from financing activities	2,529	(2,091)
Change in Cash and Cash Equivalents	0	155
Cash and Cash Equivalents at Beginning of Period	1	1
Cash and Cash Equivalents at End of Period	1	156
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	11,778	13,626
Income taxes paid (refunded), net	(299)	696
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	1,658	(1,443)
Premium on long-term debt incurred in connection with debt exchange	$ 0	$ 36,297

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Earnings Per Share

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	55,653	$	54,555	$	97,262	$	92,859
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	112		177		134		194
Average Shares – Basic	79,766		79,831		79,788		79,848
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	457		503		491		608
Average Shares – Diluted	80,223		80,334		80,279		80,456
Net Earnings Per Share of Common Stock:
Basic	$	0.70	$	0.68	$	1.22	$	1.16
Diluted	$	0.69	$	0.68	$	1.21	$	1.15

⁽¹⁾  Excludes the effect of out-of-the-money options for 435,472 shares of common stock at September 30, 2014.

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Accumulated Other Comprehensive Income (Loss) (Tables)

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2014 and 2013 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	Unrealized						Fair Value
	Gain on			Pension			Adjustment
	Available-for-			Liability			for Cash Flow
	Sale Securities			Adjustment			Hedges			Total
	(In thousands)
PNMR
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(263	)	$	(58,140	)
Amounts reclassified from AOCI (pre-tax)	(11,544		)	3,864			167			(7,513		)
Income tax impact of amounts reclassified	4,547			(1,524		)	(58		)	2,965
Other OCI changes (pre-tax)	10,202			—			(153		)	10,049
Income tax impact of other OCI changes	(3,946		)	—			53			(3,893		)
Net change after income taxes	(741		)	2,340			9			1,608
Balance at September 30, 2014	$	25,007		$	(81,285	)	$	(254	)	$	(56,532	)

PNM
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	—	$	(57,877	)
Amounts reclassified from AOCI (pre-tax)	(11,544		)	3,864			—		(7,680		)
Income tax impact of amounts reclassified	4,547			(1,524		)	—		3,023
Other OCI changes (pre-tax)	10,202			—			—		10,202
Income tax impact of other OCI changes	(3,946		)	—			—		(3,946		)
Net change after income taxes	(741		)	2,340			—		1,599
Balance at September 30, 2014	$	25,007		$	(81,285	)	$	—	$	(56,278	)

TNMP
Balance at December 31, 2013	$	—	$	—	$	(263	)	$	(263	)
Amounts reclassified from AOCI (pre-tax)	—		—		167			167
Income tax impact of amounts reclassified	—		—		(58		)	(58		)
Other OCI changes (pre-tax)	—		—		(153		)	(153		)
Income tax impact of other OCI changes	—		—		53			53
Net change after income taxes	—		—		9			9
Balance at September 30, 2014	$	—	$	—	$	(254	)	$	(254	)

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

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

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

XML

Variable Interest Entities; Acquisition (Details) (USD $)	3 Months Ended		9 Months Ended			9 Months Ended						3 Months Ended		9 Months Ended						3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 Public Service Company of New Mexico [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Delta [Member]	Jul. 17, 2014 Public Service Company of New Mexico [Member] Delta [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]	Sep. 30, 2014 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Property Lease Guarantee [Member] Maximum [Member]	Sep. 30, 2014 Valencia [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Valencia [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2014 Valencia [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Valencia [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2013 Valencia [Member] Public Service Company of New Mexico [Member]	Oct. 08, 2013 Valencia [Member] Public Service Company of New Mexico [Member]	May 30, 2008 Valencia [Member] Public Service Company of New Mexico [Member] Purchased Through May 30, 2028 [Member] MW	Sep. 30, 2014 Variable Interest Entity, Not Primary Beneficiary [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2014 Delta [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2014 Delta [Member] Public Service Company of New Mexico [Member]	Sep. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Number of mega watts purchased (in megawatts)																		158
Long Term Contract For Purchase of Electric Power Fixed Costs												$ 4,800,000	$ 4,800,000	$ 14,400,000	$ 14,100,000					$ 300,000	$ 1,600,000	$ 3,500,000	$ 4,800,000
Long Term Contract For Purchase of Electric Power Variable Charges												300,000	700,000	1,000,000	1,000,000					100,000	700,000	600,000	1,300,000
Variable Interest Entity, Statement Of Operation [Abstract]
Operating revenues												5,061,000	5,453,000	15,300,000	15,150,000
Operating expenses												(1,360,000)	(1,326,000)	(4,160,000)	(4,246,000)
Earnings attributable to non-controlling interest	3,701,000	4,127,000	11,140,000	10,904,000								3,701,000	4,127,000	11,140,000	10,904,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	466,326,000		466,326,000		401,539,000							3,435,000		3,435,000		2,658,000
Net property, plant, and equipment												73,024,000		73,024,000		75,137,000
Total assets	5,709,209,000	5,428,814,000	5,709,209,000	5,428,814,000	5,500,210,000							76,459,000		76,459,000		77,795,000
Current liabilities	700,292,000		700,292,000		492,671,000							1,039,000		1,039,000		766,000
Owners’ equity – non-controlling interest	75,420,000		75,420,000		77,029,000							75,420,000		75,420,000		77,029,000
Long term contract option to purchase, ownership percentage												50.00%
Long term contract option to purchase, purchase price - percentage of adjusted NBV												50.00%
Long term contract option to purchase, purchase price - percentage of FMV												50.00%
Long term contract option to purchase, number of days to set FMV												60 days
Long term contract option to purchase, estimated purchase price																	85,000,000
Long term contract option to purchase, approximate approval period												15 months
Operating Leases, Renewal Options After Original Lease Term (in years)			6 years			2 years
Operating Leases, Extended Lease Term Option (in years)						6 years
Operating Leases, Future Minimum Payments Due									20,300,000
Operating leases, future minimum payments due, renewal term																			145,200,000
Loss Contingency, Range of Possible Loss, Portion Not Accrued											123,800,000.0
Operating Leases, Future Minimum Payments Due, Next Six Months									11,800,000	26,000,000
Period of Long Term Contract For Purchase of Electric Power Fixed Costs																				20 years
Payments to Acquire Businesses, Gross							22,800,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt							14,600,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment								58,100,000
Business Combination, recognized identifiable assets acquired, accumulated amort								23,500,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets								3,600,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets								3,400,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities								300,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities								$ 3,400,000

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Regulatory and Rate Matters

9 Months Ended

Sep. 30, 2014

Regulated Operations [Abstract]

Regulatory and Rate Matters

Regulatory and Rate Matters

The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.

PNM

Renewable Portfolio Standard

The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements are 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015, subject to the limitation of the RCT. In December 2013, the NMPRC modified the RCT calculation to establish a two to one REC weighting for renewable energy from the non-wind/non-solar category, such as geothermal resources. On motions for rehearing, the NMPRC reversed its weighting decision in April 2014.

The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges.

The NMPRC approved PNM’s 2014 renewable energy procurement plan on December 18, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements include 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW, beginning January 1, 2015 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015.

PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements include the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $79.3 million. The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11). On September 25, 2014, a stipulated settlement was filed by PNM, staff of the NMPRC, the NMAG, NMIEC, Coalition for Clean Affordable Energy, and Western Resource Advocates. The stipulation would approve PNM’s procurement proposals; however, the costs for the 40 MW of solar would be included in base rates to be set in PNM’s next general rate case rather than through PNM’s renewable energy rider. Under the agreement, PNM will be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT. The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans. A public hearing on the stipulation was held on October 27, 2014. At the conclusion of the hearing, the Hearing Examiner asked the parties to provide her with a draft Certification of Stipulation by November 7, 2014.  PNM expects a decision by December 2, 2014.

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

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The rider will terminate upon a final order in PNM’s next general rate case unless the NMPRC authorizes PNM to continue it. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM would be required to refund the amount over 10.5% to customers during May through December of the following year. On April 1, 2014, PNM made a filing with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013. At the currently approved rider rate, PNM would collect an estimated $34.6 million annually. In its 2015 renewable energy procurement plan, PNM has proposed to increase the rate to collect $44.7 million in 2015 through its renewable energy rider.

Energy Efficiency and Load Management

Program Costs

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

In October 2012, PNM filed an energy efficiency program application for programs proposed to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive. The NMPRC approved PNM’s program application, including the annual profit incentive discussed below, on November 6, 2013.

On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. The NMPRC has not yet acted upon PNM’s application.

Disincentives/Incentives

The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. In 2010, PNM began implementing a NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. In November 2013, the NMPRC issued an order authorizing PNM to recover an incentive equal to 7.6% of annual program costs beginning with program implementation in December 2013. Based on PNM’s currently approved program costs, this equates to an estimated annual incentive of $1.7 million.

In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million. PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. The NMPRC has not yet acted upon PNM’s application.

Energy Efficiency Rulemaking

On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. Included in the proposed rule is a provision that would limit incentive awards to an amount equal to the utility’s WACC times its approved annual program costs. The NMPRC received comments and a public hearing was held on November 20, 2013. The NMPRC issued an order on October 8, 2014 adopting the proposed rule.

FPPAC Continuation Application

Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On May 28, 2013, PNM filed the required continuation application and requested that its current FPPAC be modified to increase the reset frequency of the fuel factor from annually to quarterly, to allow PNM to retain 10% of its off-system sales margin, and to apply the same carrying charge rate to both over and under collections in the balancing account. On December 20, 2013, a stipulated agreement was filed to resolve this case. On April 23, 2014, the NMPRC approved the stipulation. The settlement allows PNM to retain 10% of off-system sales margin from July 1, 2013 through December 31, 2016, resolves all costs related to the San Juan Coal mine fire discussed in Note 11, resolves the ratemaking treatment for coal pre-treatment at SJGS until the next rate case, requires PNM to write-off $10.5 million of the under-collected balance in its FPPAC balancing account, and requires PNM to extend the recovery of the remaining under-collected balance over 18 months beginning July 1, 2014. PNM recorded the $10.5 million write off as a regulatory disallowance in the fourth quarter of 2013.

Integrated Resource Plan

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3.

Applications for Approvals to Purchase Rio Bravo

As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Report on Form 10-K, PNM entered into an agreement to purchase Rio Bravo, formerly known as Delta, a 132 MW natural gas peaking unit from which PNM acquired energy and capacity under a PPA. The agreement to purchase Delta required approvals by the NMPRC and FERC. On June 26, 2013, the NMPRC granted PNM’s CCN application and approved PNM’s proposed ratemaking treatment. FERC approved the purchase on February 26, 2013. PNM closed on the purchase on July 17, 2014.

Application for Approval of La Luz Generating Station

On May 17, 2013, PNM filed an application with the NMPRC for a CCN to construct, own, and operate a 40 MW gas-fired generating facility near Belen, New Mexico. The application also requested a determination of related ratemaking principles and treatment. PNM has entered into a contract for purchase of the turbine to be used for this project and a separate contract for the construction of the facility on a turn-key basis. On February 20, 2014, a stipulated agreement was filed that would resolve the case. The parties to the stipulation are PNM, the NMPRC staff, and another intervenor. The parties to the stipulation agree that a CCN should be granted and establishes a value of up to $56.0 million to be included in rate base for the facility. A public hearing was held on April 29, 2014. The NMPRC issued an order certifying the stipulation on June 18, 2014. Construction of the facility is expected to be completed in late 2015.

San Juan Generating Station Units 2 and 3 Retirement

On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation is set forth in Note 11.

The public hearing in the NMPRC case is scheduled to begin on January 5, 2015. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM is unable to predict the outcome of these matters.

Formula Transmission Rate Case

On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. In a settlement of a prior transmission rate case, the parties agreed that no party would oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM’s proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula.

On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC’s order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC on January 2, 2013. The new rates apply to all of PNM’s wholesale electric transmission service customers. The new rates do not apply to PNM’s retail customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding.

City of Gallup, New Mexico Contract

PNM provided both energy and power services to Gallup, PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On May 1, 2013, PNM requested FERC approval of the amended agreement to be effective July 1, 2013. On June 21, 2013, FERC approved the amended agreement.

On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility.  PNM’s contract with Gallup ended on June 29, 2014.  PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014 and totaled $11.7 million during 2013.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.3 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5-year period.

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

On February 21, 2013, the PUCT filed a proposed rule to permit customers to opt-out of the AMS deployment. The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service will be borne by opt-out customers through an initial fee and ongoing monthly charge. All transmission and distribution utilities in ERCOT were required to initiate proceedings to establish these charges.

On September 30, 2013, TNMP filed an application to set the initial fee and monthly charges to be assessed for non-standard metering service provided to those retail customers who choose to decline the advanced meter necessary for standard metering service. TNMP’s filing sought recovery of $0.2 million through proposed initial fees ranging from $142.84 to $247.48 and an additional $0.5 million in annual ongoing expenses via a proposed monthly charge of $38.99. On June 20, 2014, the PUCT approved a settlement among the parties permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of October 11, 2014, the end of the initial period in which a customer could elect non-standard metering, 59 customers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor that includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On August 28, 2012, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.2 million effective January 1, 2013. On October 25, 2013, the PUCT approved a settlement that permits TNMP to collect an aggregate of $5.6 million beginning March 1, 2014. On May 30, 2014, TNMP filed its 2015 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.7 million to be collected beginning March 1, 2015. The request included an incentive bonus of $1.5 million for having achieved demand savings for the 2013 program year that exceeded the goal. On August 6, 2014, the parties filed a stipulation resolving TNMP’s application. The PUCT approved the settlement on September 11, 2014, permitting TNMP to collect $5.7 million beginning March 1, 2015. TNMP recorded the $1.5 million incentive bonus for 2013 in the three months ended September 30, 2014.

Transmission Cost of Service Rates

TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities.

On January 31, 2013, TNMP filed an application to update its transmission rates to reflect an increase in total rate base of $21.9 million, which would increase revenues $2.9 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on March 20, 2013.

On August 1, 2013, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $18.1 million, which would increase revenues by $2.8 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on September 17, 2013.

On January 21, 2014, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $18.2 million, which would increase revenues by $2.9 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on March 13, 2014.

On July 18, 2014, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $25.2 million, which would increase revenues by $4.2 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on September 8, 2014.