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 June 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 July 25, 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 July 25, 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 July 25, 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	71
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	97
ITEM 4. CONTROLS AND PROCEDURES	100
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	100
ITEM 1A. RISK FACTORS	101
ITEM 6. EXHIBITS	102
SIGNATURE	103

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
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
EPE	El Paso Electric
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

4

Luna	Luna Energy Facility
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MMBTU	Million BTUs
Moody’s	Moody’s Investor Services, Inc.
MW	Megawatt
MWh	Megawatt Hour
NAAQS	National Ambient Air Quality Standards
Navajo Acts	Navajo Nation Air Pollution Prevention and Control Act, Navajo Nation Safe Drinking Water Act, and Navajo Nation Pesticide Act
NDT	Nuclear Decommissioning Trusts for PVNGS
NEC	Navopache Electric Cooperative, Inc.
NERC	North American Electric Reliability Council
New Mexico Wind	New Mexico Wind Energy Center
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NMED	New Mexico Environment Department
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
RMC	Risk Management Committee
RPS	Renewable Energy Portfolio Standard

5

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
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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands, except per share amounts)
Electric Operating Revenues	$	346,160		$	347,599		$	675,057		$	665,263
Operating Expenses:
Cost of energy	109,419			105,659			222,033			210,365
Administrative and general	45,235			43,139			89,093			87,829
Energy production costs	45,846			46,831			93,134			90,404
Depreciation and amortization	42,163			41,639			84,130			82,446
Transmission and distribution costs	16,068			17,148			32,974			33,443
Taxes other than income taxes	16,133			15,316			33,644			32,205
Total operating expenses	274,864			269,732			555,008			536,692
Operating income	71,296			77,867			120,049			128,571
Other Income and Deductions:
Interest income	2,040			2,833			4,158			5,467
Gains on available-for-sale securities	4,699			3,217			7,272			4,747
Other income	3,180			2,610			4,754			4,323
Other (deductions)	(2,169		)	(4,194		)	(5,102		)	(7,546		)
Net other income and deductions	7,750			4,466			11,082			6,991
Interest Charges	29,972			30,616			59,506			61,914
Earnings before Income Taxes	49,074			51,717			71,625			73,648
Income Taxes	15,893			20,334			22,313			28,303
Net Earnings	33,181			31,383			49,312			45,345
(Earnings) Attributable to Valencia Non-controlling Interest	(3,908		)	(3,573		)	(7,439		)	(6,777		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(264		)	(264		)
Net Earnings Attributable to PNMR	$	29,141		$	27,678		$	41,609		$	38,304
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.37		$	0.35		$	0.52		$	0.48
Diluted	$	0.36		$	0.34		$	0.52		$	0.48
Dividends Declared per Common Share	$	0.185		$	0.165		$	0.370		$	0.330

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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Net Earnings	$	33,181		$	31,383		$	49,312		$	45,345
Other Comprehensive Income:
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(2,602), $(290), $(3,809) and $(3,401)	3,999			443			6,046			5,190
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $2,210, $2,185, $3,488 and $2,714	(3,397		)	(3,333		)	(5,369		)	(4,140		)
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), $(1,016) and $(1,262)	780			960			1,560			1,920
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $3, $53 and $(1)	—			(6		)	(100		)	2
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(42), $(18), $(61) and $(35)	79			33			115			64
Total Other Comprehensive Income (Loss)	1,461			(1,903		)	2,252			3,036
Comprehensive Income	34,642			29,480			51,564			48,381
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,908		)	(3,573		)	(7,439		)	(6,777		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(264		)	(264		)
Comprehensive Income Attributable to PNMR	$	30,602		$	25,775		$	43,861		$	41,340

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)

	Six Months Ended June 30,
	2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	49,312		$	45,345
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	103,436			103,914
Deferred income tax expense	24,252			27,797
Net unrealized (gains) losses on commodity derivatives	3,187			1,729
Realized (gains) on available-for-sale securities	(7,272		)	(4,747		)
Stock based compensation expense	3,399			3,198
Other, net	38			255
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(17,543		)	(23,021		)
Materials, supplies, and fuel stock	6,346			(159		)
Other current assets	(20,688		)	3,870
Other assets	18,237			6,356
Accounts payable	(29,384		)	(7,424		)
Accrued interest and taxes	(2,830		)	93,077
Other current liabilities	(3,341		)	(21,310		)
Other liabilities	(3,343		)	(68,972		)
Net cash flows from operating activities	123,806			159,908
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(160,893		)	(153,512		)
Proceeds from sales of available-for-sale securities	53,119			76,106
Purchases of available-for-sale securities	(54,338		)	(77,882		)
Return of principal on PVNGS lessor notes	10,231			10,965
Other, net	750			1,254
Net cash flows from investing activities	(151,131		)	(143,069		)

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)

	Six Months Ended June 30,
	2014			2013
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(44,200		)	1,300
Long-term borrowings	255,000			75,000
Repayment of long-term debt	(125,000		)	(9,445		)
Cash paid in debt exchange	—			(13,048		)
Proceeds from stock option exercise	4,446			11,345
Awards of common stock	(13,939		)	(19,741		)
Dividends paid	(29,732		)	(24,958		)
Valencia’s transactions with its owner	(8,189		)	(8,675		)
Other, net	(1,482		)	(2,804		)
Net cash flows from financing activities	36,904			8,974
Change in Cash and Cash Equivalents	9,579			25,813
Cash and Cash Equivalents at Beginning of Period	2,533			8,985
Cash and Cash Equivalents at End of Period	$	12,112		$	34,798
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	54,712		$	58,267
Income taxes paid (refunded), net	$	(2,534	)	$	(95,472	)
Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(7,909	)	$	(3,375	)
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)

	June 30, 2014		December 31, 2013
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	12,112	$	2,533
Accounts receivable, net of allowance for uncollectible accounts of $1,535 and $1,423	92,230		90,251
Unbilled revenues	72,690		58,806
Other receivables	40,369		53,909
Materials, supplies, and fuel stock	60,877		67,223
Regulatory assets	45,287		24,416
Commodity derivative instruments	4,082		4,064
Income taxes receivable	6,471		7,066
Current portion of accumulated deferred income taxes	58,681		58,681
Other current assets	54,026		34,590
Total current assets	446,825		401,539
Other Property and Investments:
Investment in PVNGS lessor notes	17,519		32,200
Available-for-sale securities	236,427		226,855
Other investments	1,798		1,835
Non-utility property	4,284		4,353
Total other property and investments	260,028		265,243
Utility Plant:
Plant in service and plant held for future use	5,659,379		5,563,061
Less accumulated depreciation and amortization	1,860,816		1,838,832
	3,798,563		3,724,229
Construction work in progress	146,760		132,080
Nuclear fuel, net of accumulated amortization of $44,785 and $47,347	78,216		77,602
Net utility plant	4,023,539		3,933,911
Deferred Charges and Other Assets:
Regulatory assets	499,640		523,955
Goodwill	278,297		278,297
Commodity derivative instruments	1,515		3,002
Other deferred charges	94,348		94,263
Total deferred charges and other assets	873,800		899,517
	$	5,604,192	$	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)

	June 30, 2014			December 31, 2013
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	105,000		$	149,200
Current installments of long-term debt	158,066			75,000
Accounts payable	88,191			109,666
Customer deposits	12,914			13,456
Accrued interest and taxes	46,564			49,600
Regulatory liabilities	473			1,081
Commodity derivative instruments	5,073			2,699
Dividends declared	132			14,864
Other current liabilities	70,456			77,105
Total current liabilities	486,869			492,671
Long-term Debt	1,717,188			1,670,420
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	852,846			801,408
Accumulated deferred investment tax credits	24,773			25,855
Regulatory liabilities	465,176			460,649
Asset retirement obligations	100,100			96,135
Accrued pension liability and postretirement benefit cost	72,726			80,046
Commodity derivative instruments	915			1,094
Other deferred credits	99,257			109,805
Total deferred credits and other liabilities	1,615,793			1,574,992
Total liabilities	3,819,850			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)	1,172,209			1,178,369
Accumulated other comprehensive income (loss), net of income taxes	(55,888		)	(58,140		)
Retained earnings	580,213			553,340
Total PNMR common stockholders’ equity	1,696,534			1,673,569
Non-controlling interest in Valencia	76,279			77,029
Total equity	1,772,813			1,750,598
	$	5,604,192		$	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	4,446			—			—			4,446			—			4,446
Awards of common stock	(13,939		)	—			—			(13,939		)	—			(13,939		)
Excess tax (shortfall) from stock-based payment arrangements	(66		)	—			—			(66		)	—			(66		)
Stock based compensation expense	3,399			—			—			3,399			—			3,399
Valencia’s transactions with its owner	—			—			—			—			(8,189		)	(8,189		)
Net earnings before subsidiary preferred stock dividends	—			—			41,873			41,873			7,439			49,312
Subsidiary preferred stock dividends	—			—			(264		)	(264		)	—			(264		)
Total other comprehensive income	—			2,252			—			2,252			—			2,252
Dividends declared on common stock	—			—			(14,736		)	(14,736		)	—			(14,736		)
Balance at June 30, 2014	$	1,172,209		$	(55,888	)	$	580,213		$	1,696,534		$	76,279		$	1,772,813

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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Electric Operating Revenues	$	275,704		$	279,690		$	538,441		$	537,583
Operating Expenses:
Cost of energy	92,642			91,855			189,268			183,514
Administrative and general	40,603			36,622			79,213			75,381
Energy production costs	45,846			46,836			93,134			90,402
Depreciation and amortization	27,023			26,051			54,105			51,884
Transmission and distribution costs	10,183			11,133			21,510			21,735
Taxes other than income taxes	9,601			8,891			20,100			19,125
Total operating expenses	225,898			221,388			457,330			442,041
Operating income	49,806			58,302			81,111			95,542
Other Income and Deductions:
Interest income	2,065			2,868			4,193			5,541
Gains on available-for-sale securities	4,699			3,217			7,272			4,747
Other income	2,443			1,614			3,555			2,930
Other (deductions)	(1,630		)	(1,471		)	(3,647		)	(2,911		)
Net other income and deductions	7,577			6,228			11,373			10,307
Interest Charges	20,023			19,890			39,835			39,847
Earnings before Income Taxes	37,360			44,640			52,649			66,002
Income Taxes	13,106			14,943			17,189			21,532
Net Earnings	24,254			29,697			35,460			44,470
(Earnings) Attributable to Valencia Non-controlling Interest	(3,908		)	(3,573		)	(7,439		)	(6,777		)
Net Earnings Attributable to PNM	20,346			26,124			28,021			37,693
Preferred Stock Dividends Requirements	(132		)	(132		)	(264		)	(264		)
Net Earnings Available for PNM Common Stock	$	20,214		$	25,992		$	27,757		$	37,429

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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Net Earnings	$	24,254		$	29,697		$	35,460		$	44,470
Other Comprehensive Income:
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(2,602), $(290), $(3,809) and $(3,401)	3,999			443			6,046			5,190
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $2,210, $2,185, $3,488 and $2,714	(3,397		)	(3,333		)	(5,369		)	(4,140		)
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), $(1,016) and $(1,262)	780			960			1,560			1,920
Total Other Comprehensive Income (Loss)	1,382			(1,930		)	2,237			2,970
Comprehensive Income	25,636			27,767			37,697			47,440
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,908		)	(3,573		)	(7,439		)	(6,777		)
Comprehensive Income Attributable to PNM	$	21,728		$	24,194		$	30,258		$	40,663

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)

	Six Months Ended June 30,
	2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	35,460		$	44,470
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	71,327			69,179
Deferred income tax expense	19,716			21,836
Net unrealized (gains) losses on commodity derivatives	3,187			1,729
Realized (gains) on available-for-sale securities	(7,272		)	(4,747		)
Other, net	193			(876		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(13,885		)	(15,841		)
Materials, supplies, and fuel stock	6,447			(238		)
Other current assets	(22,588		)	4,299
Other assets	18,790			6,196
Accounts payable	(26,737		)	(5,829		)
Accrued interest and taxes	(1,575		)	45,380
Other current liabilities	3,943			(23,523		)
Other liabilities	(3,193		)	(69,059		)
Net cash flows from operating activities	83,813			72,976
Cash Flows From Investing Activities:
Utility plant additions	(92,567		)	(98,673		)
Proceeds from sales of available-for-sale securities	53,119			76,106
Purchases of available-for-sale securities	(54,338		)	(77,882		)
Return of principal on PVNGS lessor notes	10,231			10,965
Other, net	(70		)	1,227
Net cash flows from investing activities	(83,625		)	(88,257		)

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)

	Six Months Ended June 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	(32,500		)	—
Long-term borrowings	175,000			75,000
Repayment of long-term debt	(75,000		)	—
Valencia’s transactions with its owner	(8,189		)	(8,675		)
Dividends paid	(264		)	(264		)
Other, net	(700		)	(1,169		)
Net cash flows from financing activities	9,147			43,792
Change in Cash and Cash Equivalents	9,335			28,511
Cash and Cash Equivalents at Beginning of Period	21			3,958
Cash and Cash Equivalents at End of Period	$	9,356		$	32,469
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	36,601		$	37,845
Income taxes paid (refunded), net	$	(215	)	$	(44,999	)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	$	(5,595	)	$	817

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)

	June 30, 2014		December 31, 2013
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	9,356	$	21
Accounts receivable, net of allowance for uncollectible accounts of $1,535 and $1,423	68,254		70,126
Unbilled revenues	63,069		48,992
Other receivables	39,354		52,964
Affiliate receivables	11,269		10,054
Materials, supplies, and fuel stock	58,073		64,520
Regulatory assets	40,089		19,394
Commodity derivative instruments	4,082		4,064
Income taxes receivable	6,342		4,030
Current portion of accumulated deferred income taxes	43,826		43,827
Other current assets	49,385		30,510
Total current assets	393,099		348,502
Other Property and Investments:
Investment in PVNGS lessor notes	17,519		32,200
Available-for-sale securities	236,427		226,855
Other investments	432		445
Non-utility property	976		976
Total other property and investments	255,354		260,476
Utility Plant:
Plant in service and plant held for future use	4,375,493		4,314,016
Less accumulated depreciation and amortization	1,426,935		1,402,531
	2,948,558		2,911,485
Construction work in progress	114,601		107,344
Nuclear fuel, net of accumulated amortization of $44,785 and $47,347	78,216		77,602
Net utility plant	3,141,375		3,096,431
Deferred Charges and Other Assets:
Regulatory assets	365,239		384,217
Goodwill	51,632		51,632
Commodity derivative instruments	1,515		3,002
Other deferred charges	82,315		83,356
Total deferred charges and other assets	500,701		522,207
	$	4,290,529	$	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)

	June 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	—			32,500
Current installments of long-term debt	39,300			75,000
Accounts payable	63,501			84,643
Affiliate payables	23,053			20,498
Customer deposits	12,914			13,456
Accrued interest and taxes	29,207			27,665
Regulatory liabilities	473			1,081
Commodity derivative instruments	5,073			2,699
Dividends declared	132			132
Other current liabilities	52,650			50,392
Total current liabilities	226,303			357,266
Long-term Debt	1,351,337			1,215,618
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	689,190			651,239
Accumulated deferred investment tax credits	24,773			25,855
Regulatory liabilities	418,178			414,611
Asset retirement obligations	99,152			95,225
Accrued pension liability and postretirement benefit cost	69,624			76,611
Commodity derivative instruments	915			1,094
Other deferred credits	83,056			91,340
Total deferred credits and liabilities	1,384,888			1,355,975
Total liabilities	2,962,528			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	(55,640		)	(57,877		)
Retained earnings	234,057			206,300
Total PNM common stockholder’s equity	1,240,193			1,210,199
Non-controlling interest in Valencia	76,279			77,029
Total equity	1,316,472			1,287,228
	$	4,290,529		$	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	—		—			—			—			(8,189		)	(8,189		)
Net earnings	—		—			28,021			28,021			7,439			35,460
Total other comprehensive income	—		2,237			—			2,237			—			2,237
Dividends declared on preferred stock	—		—			(264		)	(264		)	—			(264		)
Balance at June 30, 2014	$	1,061,776	$	(55,640	)	$	234,057		$	1,240,193		$	76,279		$	1,316,472

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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Electric Operating Revenues	$	70,456		$	67,909		$	136,616		$	127,680
Operating Expenses:
Cost of energy	16,777			13,804			32,765			26,851
Administrative and general	8,768			10,686			18,609			21,804
Depreciation and amortization	12,003			12,279			23,844			23,960
Transmission and distribution costs	5,885			6,016			11,464			11,708
Taxes other than income taxes	5,758			5,457			11,408			10,636
Total operating expenses	49,191			48,242			98,090			94,959
Operating income	21,265			19,667			38,526			32,721
Other Income and Deductions:
Other income	586			609			1,006			946
Other (deductions)	(72		)	(123		)	(304		)	(252		)
Net other income and deductions	514			486			702			694
Interest Charges	6,655			6,759			13,252			14,005
Earnings before Income Taxes	15,124			13,394			25,976			19,410
Income Taxes	5,590			5,055			9,640			7,345
Net Earnings	$	9,534		$	8,339		$	16,336		$	12,065

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 June 30,					Six Months Ended June 30,
	2014		2013			2014			2013
	(In thousands)
Net Earnings	$	9,534	$	8,339		$	16,336		$	12,065
Other Comprehensive Income (Loss):
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $3, $53 and $(1)	—		(6		)	(100		)	2
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(42), $(18), $(61) and $(35)	79		33			115			64
Total Other Comprehensive Income	79		27			15			66
Comprehensive Income	$	9,613	$	8,366		$	16,351		$	12,131

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)

	Six Months Ended June 30,
	2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	16,336		$	12,065
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	25,728			26,034
Deferred income tax expense	6,162			4,348
Other, net	(38		)	(10		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(3,658		)	(7,180		)
Materials and supplies	(101		)	79
Other current assets	(803		)	(4,082		)
Other assets	(273		)	590
Accounts payable	1,381			807
Accrued interest and taxes	(726		)	(1,517		)
Other current liabilities	2,167			1,278
Other liabilities	365			886
Net cash flows from operating activities	46,540			33,298
Cash Flows From Investing Activities:
Utility plant additions	(64,502		)	(47,390		)
Net cash flows from investing activities	(64,502		)	(47,390		)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	—			25,000
Short-term borrowings (repayments) – affiliate, net	(4,200		)	7,500
Long-term borrowings	80,000			—
Repayment of long-term debt	(50,000		)	—
Cash paid in debt exchange	—			(13,048		)
Dividends paid	(6,803		)	(3,726		)
Other, net	(783		)	(1,634		)
Net cash flows from financing activities	18,214			14,092
Change in Cash and Cash Equivalents	252			—
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	253		$	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	11,847		$	13,267
Income taxes paid (refunded), net	$	(304	)	$	696
Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	1,038		$	(886	)
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)

	June 30, 2014		December 31, 2013
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	253	$	1
Accounts receivable	23,976		20,125
Unbilled revenues	9,621		9,814
Other receivables	1,341		1,246
Materials and supplies	2,804		2,703
Regulatory assets	5,198		5,022
Current portion of accumulated deferred income taxes	6,501		6,501
Other current assets	1,662		980
Total current assets	51,356		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	1,119,014		1,074,193
Less accumulated depreciation and amortization	362,640		352,105
	756,374		722,088
Construction work in progress	27,633		16,790
Net utility plant	784,007		738,878
Deferred Charges and Other Assets:
Regulatory assets	134,401		139,738
Goodwill	226,665		226,665
Other deferred charges	9,603		8,273
Total deferred charges and other assets	370,669		374,676
	$	1,208,517	$	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)

	June 30, 2014			December 31, 2013
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt – affiliate	$	25,200		$	29,400
Accounts payable	14,945			12,543
Affiliate payables	3,941			3,181
Accrued interest and taxes	23,052			23,778
Other current liabilities	3,602			8,999
Total current liabilities	70,740			77,901
Long-term Debt	365,851			336,036
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	203,289			190,197
Regulatory liabilities	46,998			46,038
Asset retirement obligations	815			782
Accrued pension liability and postretirement benefit cost	3,102			3,435
Other deferred credits	5,243			5,111
Total deferred credits and other liabilities	259,447			245,563
Total liabilities	696,038			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	(248		)	(263		)
Retained earnings	108,497			98,964
Total common stockholder’s equity	512,479			502,931
	$	1,208,517		$	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	—		—		—			16,336			16,336
Total other comprehensive income	—		—		15			—			15
Dividends declared on common stock	—		—		—			(6,803		)	(6,803		)
Balance at June 30, 2014	$	64	$	404,166	$	(248	)	$	108,497		$	512,479

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 June 30, 2014 and December 31, 2013, the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2014 and 2013, and the consolidated cash flows for the six months ended June 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 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.

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)

TNMP declared and paid cash dividends of $6.8 million and $3.7 million in the six months ended June 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

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.

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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	29,141	$	27,678	$	41,609	$	38,304
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	110		194		146		202
Average Shares – Basic	79,764		79,848		79,800		79,856
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	464		607		508		661
Average Shares – Diluted	80,228		80,455		80,308		80,517
Net Earnings Per Share of Common Stock:
Basic	$	0.37	$	0.35	$	0.52	$	0.48
Diluted	$	0.36	$	0.34	$	0.52	$	0.48

⁽¹⁾  Excludes the effect of out-of-the-money options for 297,350 shares of common stock at June 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 June 30, 2014
Electric operating revenues	$	275,704		$	70,456		$	—		$	346,160
Cost of energy	92,642			16,777			—			109,419
Margin	183,062			53,679			—			236,741
Other operating expenses	106,233			20,411			(3,362		)	123,282
Depreciation and amortization	27,023			12,003			3,137			42,163
Operating income	49,806			21,265			225			71,296
Interest income	2,065			—			(25		)	2,040
Other income (deductions)	5,512			514			(316		)	5,710
Net interest charges	(20,023		)	(6,655		)	(3,294		)	(29,972		)
Segment earnings (loss) before income taxes	37,360			15,124			(3,410		)	49,074
Income taxes (benefit)	13,106			5,590			(2,803		)	15,893
Segment earnings (loss)	24,254			9,534			(607		)	33,181
Valencia non-controlling interest	(3,908		)	—			—			(3,908		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	20,214		$	9,534		$	(607	)	$	29,141
Six Months Ended June 30, 2014
Electric operating revenues	$	538,441		$	136,616		$	—		$	675,057
Cost of energy	189,268			32,765			—			222,033
Margin	349,173			103,851			—			453,024
Other operating expenses	213,957			41,481			(6,593		)	248,845
Depreciation and amortization	54,105			23,844			6,181			84,130
Operating income	81,111			38,526			412			120,049
Interest income	4,193			—			(35		)	4,158
Other income (deductions)	7,180			702			(958		)	6,924
Net interest charges	(39,835		)	(13,252		)	(6,419		)	(59,506		)
Segment earnings (loss) before income taxes	52,649			25,976			(7,000		)	71,625
Income taxes (benefit)	17,189			9,640			(4,516		)	22,313
Segment earnings (loss)	35,460			16,336			(2,484		)	49,312
Valencia non-controlling interest	(7,439		)	—			—			(7,439		)
Subsidiary preferred stock dividends	(264		)	—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	27,757		$	16,336		$	(2,484	)	$	41,609
At June 30, 2014:
Total Assets	$	4,290,529		$	1,208,517		$	105,146		$	5,604,192
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 June 30, 2013
Electric operating revenues	$	279,690		$	67,909		$	—		$	347,599
Cost of energy	91,855			13,804			—			105,659
Margin	187,835			54,105			—			241,940
Other operating expenses	103,482			22,159			(3,207		)	122,434
Depreciation and amortization	26,051			12,279			3,309			41,639
Operating income (loss)	58,302			19,667			(102		)	77,867
Interest income	2,868			—			(35		)	2,833
Other income (deductions)	3,360			486			(2,213		)	1,633
Net interest charges	(19,890		)	(6,759		)	(3,967		)	(30,616		)
Segment earnings (loss) before income taxes	44,640			13,394			(6,317		)	51,717
Income taxes (benefit)	14,943			5,055			336			20,334
Segment earnings (loss)	29,697			8,339			(6,653		)	31,383
Valencia non-controlling interest	(3,573		)	—			—			(3,573		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	25,992		$	8,339		$	(6,653	)	$	27,678
Six Months Ended June 30, 2013
Electric operating revenues	$	537,583		$	127,680		$	—		$	665,263
Cost of energy	183,514			26,851			—			210,365
Margin	354,069			100,829			—			454,898
Other operating expenses	206,643			44,148			(6,910		)	243,881
Depreciation and amortization	51,884			23,960			6,602			82,446
Operating income	95,542			32,721			308			128,571
Interest income	5,541			—			(74		)	5,467
Other income (deductions)	4,766			694			(3,936		)	1,524
Net interest charges	(39,847		)	(14,005		)	(8,062		)	(61,914		)
Segment earnings (loss) before income taxes	66,002			19,410			(11,764		)	73,648
Income taxes (benefit)	21,532			7,345			(574		)	28,303
Segment earnings (loss)	44,470			12,065			(11,190		)	45,345
Valencia non-controlling interest	(6,777		)	—			—			(6,777		)
Subsidiary preferred stock dividends	(264		)	—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	37,429		$	12,065		$	(11,190	)	$	38,304
At June 30, 2013:
Total Assets	$	4,185,189		$	1,155,928		$	62,789		$	5,403,906
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 six months ended June 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)	(8,857		)	2,576			176			(6,105		)
Income tax impact of amounts reclassified	3,488			(1,016		)	(61		)	2,411
Other OCI changes (pre-tax)	9,855			—			(153		)	9,702
Income tax impact of other OCI changes	(3,809		)	—			53			(3,756		)
Net change after income taxes	677			1,560			15			2,252
Balance at June 30, 2014	$	26,425		$	(82,065	)	$	(248	)	$	(55,888	)

PNM
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	—	$	(57,877	)
Amounts reclassified from AOCI (pre-tax)	(8,857		)	2,576			—		(6,281		)
Income tax impact of amounts reclassified	3,488			(1,016		)	—		2,472
Other OCI changes (pre-tax)	9,855			—			—		9,855
Income tax impact of other OCI changes	(3,809		)	—			—		(3,809		)
Net change after income taxes	677			1,560			—		2,237
Balance at June 30, 2014	$	26,425		$	(82,065	)	$	—	$	(55,640	)

TNMP
Balance at December 31, 2013	$	—	$	—	$	(263	)	$	(263	)
Amounts reclassified from AOCI (pre-tax)	—		—		176			176
Income tax impact of amounts reclassified	—		—		(61		)	(61		)
Other OCI changes (pre-tax)	—		—		(153		)	(153		)
Income tax impact of other OCI changes	—		—		53			53
Net change after income taxes	—		—		15			15
Balance at June 30, 2014	$	—	$	—	$	(248	)	$	(248	)

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)	(6,854		)	3,182			99			(3,573		)
Income tax impact of amounts reclassified	2,714			(1,262		)	(35		)	1,417
Other OCI changes (pre-tax)	8,591			—			3			8,594
Income tax impact of other OCI changes	(3,401		)	—			(1		)	(3,402		)
Net change after income taxes	1,050			1,920			66			3,036
Balance at June 30, 2013	$	17,456		$	(95,900	)	$	(150	)	$	(78,594	)

PNM
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	—	$	(81,414	)
Amounts reclassified from AOCI (pre-tax)	(6,854		)	3,182			—		(3,672		)
Income tax impact of amounts reclassified	2,714			(1,262		)	—		1,452
Other OCI changes (pre-tax)	8,591			—			—		8,591
Income tax impact of other OCI changes	(3,401		)	—			—		(3,401		)
Net change after income taxes	1,050			1,920			—		2,970
Balance at June 30, 2013	$	17,456		$	(95,900	)	$	—	$	(78,444	)

TNMP
Balance at December 31, 2012	$	—	$	—	$	(216	)	$	(216	)
Amounts reclassified from AOCI (pre-tax)	—		—		99			99
Income tax impact of amounts reclassified	—		—		(35		)	(35		)
Other OCI changes (pre-tax)	—		—		3			3
Income tax impact of other OCI changes	—		—		(1		)	(1		)
Net change after income taxes	—		—		66			66
Balance at June 30, 2013	$	—	$	—	$	(150	)	$	(150	)

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 six months ended June 30, 2014 and 2013, approximately 23.0% and 16.4% of the amount reclassified was capitalized into construction work in process and approximately 2.1% and 2.5% 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

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 six months ended June 30, 2014, PNM paid $4.8 million and $9.6 million for fixed charges and $0.5 million and $0.7 million for variable charges. For the three and six months ended June 30, 2013, PNM paid $4.7 million and $9.4 million for fixed charges and $0.2 million and $0.3 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM has 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Operating revenues	$	5,307		$	4,922		$	10,238		$	9,697
Operating expenses	(1,399		)	(1,349		)	(2,799		)	(2,920		)
Earnings attributable to non-controlling interest	$	3,908		$	3,573		$	7,439		$	6,777

Financial Position

	June 30,		December 31,
	2014		2013
	(In thousands)
Current assets	$	3,232	$	2,658
Net property, plant, and equipment	73,729		75,137
Total assets	76,961		77,795
Current liabilities	682		766
Owners’ equity – non-controlling interest	$	76,279	$	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; 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, which, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, aggregate $36.5 million as of June 30, 2014 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 June 30, 2014, PNM could have been required to pay the beneficial owners up to $144.7 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 $26.0 million at June 30, 2014 and December 31, 2013, that are included in other current liabilities on the Condensed Consolidated Balance Sheets.

Delta

PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which is 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 owns Delta. PNM made fixed and variable payments to Delta under the PPA. For the three and six months ended June 30, 2014, PNM incurred fixed capacity charges of $1.6 million and $3.2 million and variable energy charges of $0.3 million and $0.5 million under the PPA. For the three and six months ended June 30, 2013, PNM incurred

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)

fixed capacity charges of $1.6 million and $3.2 million and variable energy charges of $0.4 million and $0.6 million. PNM’s only quantifiable obligation under the PPA was to make the fixed payments, which as of June 30, 2014 aggregated $36.2 million through the end of the PPA. PNM would also pay variable costs, which could not be quantified since the amounts were based on how much the generating plant operated.

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 owns Delta, or to consolidate that entity if it were determined that PNM is 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 owns 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 estimated 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 June 30, 2014 and at closing.

Delta informed PNM that at June 30, 2014 and December 31, 2013, it had total assets of $22.4 million and $23.7 million, including net property, plant, and equipment of $19.0 million and $20.3 million, and total liabilities of $16.5 million and $18.2 million. Delta also indicated its revenue for the three and six months ended June 30, 2014 was $2.5 million and $4.3 million and its net earnings were $0.3 million and $0.6 million. Revenue for the three and six months ended June 30, 2013 was $2.2 million and $4.0 million and net earnings were $0.1 million and $0.3 million. Consolidation of Delta would be immaterial to the Condensed Consolidated Balance Sheets of PNMR and PNM. Since all of Delta’s revenues and expenses are 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 be 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 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.

36

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the 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 31.2494 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 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

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)

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 six months ended June 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
	June 30, 2014			December 31, 2013
PNMR and PNM	(In thousands)
Current assets	$	4,082		$	4,064
Deferred charges	1,515			3,002
	5,597			7,066
Current liabilities	(5,073		)	(2,699		)
Long-term liabilities	(915		)	(1,094		)
	(5,988		)	(3,793		)
Net	$	(391	)	$	3,273

Included in the above table are $3.0 million of current assets and $1.5 million of deferred charges at June 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 June 30, 2014 and December 31, 2013.

At June 30, 2014 and December 31, 2013, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at June 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 $0.1 million

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)

at June 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 $0.4 million of current assets and $0.6 million of current liabilities at June 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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
PNMR and PNM	(In thousands)
Electric operating revenues	$	(324	)	$	3,269		$	(4,475	)	$	(1,334	)
Cost of energy	57			(263		)	245			493
Total gain (loss)	$	(267	)	$	3,006		$	(4,230	)	$	(841	)

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
June 30, 2014
PNMR and PNM	1,165,000	(2,809,507	)
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)
June 30, 2014
PNMR and PNM	$	2,740	$	—	$	1,663
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 June 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 June 30, 2014 and December 31, 2013, the fair value of available-for-sale securities included $231.9 million and $222.5 million for the NDT and $4.5 million and $4.4 million for the mine reclamation trust.

	June 30, 2014				December 31, 2013
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,114	$	—	$	3,356
Equity securities:
Domestic value	16,014		42,664		14,523		39,460
Domestic growth	19,931		75,621		25,656		76,292
International and other	2,227		17,848		1,040		16,633
Fixed income securities:
U.S. Government	534		19,814		158		21,941
Municipals	4,282		65,872		1,018		58,568
Corporate and other	625		11,494		207		10,605
	$	43,613	$	236,427	$	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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In thousands)
Proceeds from sales	$	30,316		$	61,821		$	53,119		$	76,106
Gross realized gains	$	5,364		$	4,905		$	8,482		$	6,243
Gross realized (losses)	$	(665	)	$	(1,688	)	$	(1,210	)	$	(1,496	)

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 June 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	$	2,911	$	12,017	$	12,017
After 1 year through 5 years	21,556		33,776		33,050
After 5 years through 10 years	10,875		—		—
After 10 years through 15 years	9,114		—		—
After 15 years through 20 years	11,431		—		—
After 20 years	41,293		—		—
	$	97,180	$	45,793	$	45,067

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 June 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)
June 30, 2014	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,114		$	3,114	$	—
Equity securities:
Domestic value	42,664			42,664		—
Domestic growth	75,621			75,621		—
International and other	17,848			17,848		—
Fixed income securities:
U.S. Government	19,814			18,053		1,761
Municipals	65,872			—		65,872
Corporate and other	11,494			2,481		9,013
	$	236,427		$	159,781	$	76,646
Commodity derivative assets	$	5,597		$	—	$	5,597
Commodity derivative liabilities	(5,988		)	—		(5,988		)
Net	$	(391	)	$	—	$	(391	)
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 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 six months ended June 30, 2014 and the year ended December 31, 2013.

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
June 30, 2014	(In thousands)
PNMR
Long-term debt	$	1,875,254	$	2,088,787	$	—	$	2,088,787	$	—
Investment in PVNGS lessor notes	$	42,234	$	45,067	$	—	$	—	$	45,067
Other investments	$	1,798	$	2,525	$	677	$	—	$	1,848
PNM
Long-term debt	$	1,390,637	$	1,530,418	$	—	$	1,530,418	$	—
Investment in PVNGS lessor notes	$	42,234	$	45,067	$	—	$	—	$	45,067
Other investments	$	432	$	432	$	432	$	—	$	—
TNMP
Long-term debt	$	365,851	$	431,706	$	—	$	431,706	$	—
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	$	—	$	—

(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 June 30, 2014 and December 31, 2013, PNMR had unrecognized expense related to stock awards of $7.7 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:

	Six Months Ended June 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 six months endedJune 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	(236,260	)	$	18.90	(292,052	)	$	16.64
Forfeited	(17,151	)	$	26.43	—		$	—
Expired	(22,784	)	$	25.91	—		$	—
Outstanding at end of period	1,067,471		$	20.80	265,417		$	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 June 30, 2014, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $9.4 million with a weighted-average remaining contract life of 3.20 years. At June 30, 2014, the exercise price of 297,350 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:

	Six Months Ended June 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)	$	1,779	$	2,189
Restricted Stock
Weighted-average grant date fair value	$	21.27	$	20.03
Total fair value of restricted shares that vested (in thousands)	$	4,854	$	4,383

(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 June 30, 2014, must be repaid on or before September 4, 2015, and is reflected as 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

45

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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)

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 June 30, 2014, the weighted average interest rate was 1.66% for borrowings under the PNMR Revolving Credit Facility and 1.00% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2014. Short-term debt outstanding consisted of:

	June 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	5,000		—
PNMR Term Loan Agreement	100,000		100,000
	$	105,000	$	149,200

At July 25, 2014, PNMR, PNM, and TNMP had $292.3 million, $369.6 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 $35.0 million of availability under the PNM New Mexico Credit Facility. Total availability at July 25, 2014, on a consolidated basis, was $771.8 million for PNMR. As of July 25, 2014, PNM had $5.5 million in borrowings from PNMR and TNMP had $25.7 million in borrowings from PNMR under their intercompany loan agreements. At July 25, 2014, PNMR, PNM and TNMP had consolidated invested cash of $1.9 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 (“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 has proposed a change in mortality assumptions to reflect increased life expectancy and the corresponding decrease in mortality rates.  If adopted, 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, beginning in 2016, the Company’s

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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)

pension liabilities could increase by as much as 7% over those using the current mortality assumptions.  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 June 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
	Six Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	91		$	130		$	—	$	—
Interest cost	15,082			14,071			2,315			2,057			411		360
Expected return on plan assets	(19,022		)	(20,965		)	(2,819		)	(2,522		)	—		—
Amortization of net (gain) loss	6,510			7,420			1,113			2,121			105		116
Amortization of prior service cost	(483		)	38			(672		)	(672		)	—		—
Net periodic benefit cost	$	2,087		$	564		$	28		$	1,114		$	516	$	476

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 six months ended June 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 $61.5 million. These anticipated contributions were developed using current funding assumptions, with discount rates of 5.2% to 5.5%. 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 $1.6 million in the three and six months ended June 30, 2014 and $1.1 million and $1.6 million in the three and six months ended June 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 $0.7 million in the three and six months ended June 30, 2014 and $0.4 million and $0.8 million in the three and six months ended June 30, 2013 and are expected to total $1.5 million during 2014.

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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)

TNMP Plans

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

	Three Months Ended June 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
	Six Months Ended June 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	$	—		$	—		$	119		$	150		$	—	$	—
Interest cost	1,597			1,544			309			283			20		18
Expected return on plan assets	(2,263		)	(2,425		)	(267		)	(252		)	—		—
Amortization of net (gain) loss	333			524			(61		)	—			—		—
Amortization of prior service cost	—			—			16			28			—		—
Net Periodic Benefit Cost (Income)	$	(333	)	$	(357	)	$	116		$	209		$	20	$	18

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 six months ended June 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 5.2% and 5.5%. 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 $0.3 million in the three and six months ended June 30, 2014 and $0.3 million in the three and six months ended June 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 six months ended June 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. 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. PNM is unable to predict the outcome of this matter.

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 June 30, 2014 and December 31, 2013, PNM had a liability for interim storage costs of $12.1 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

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)

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. NRC Commissioners have instructed the staff to issue the final generic EIS and rule by no later than September 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. The fee applicable to PVNGS Units 1 and 2 is recovered by PNM in its retail rates. 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. In 2013, the one-mill fee for PNM’s share of the output from all three units at PVNGS amounted to $3.0 million. 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. 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 requires installation of selective catalytic reduction technology (“SCR”) with stringent NOx emission limits on all four units by September 21, 2016.

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 on March 1, 2012. These parties also formally asked EPA to stay the effective date of the rule. Several environmental groups have intervened in support of EPA. WEG also filed an action to challenge EPA’s rule in the Tenth Circuit, seeking to shorten the rule’s compliance period from five

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)

years to three years and PNM has intervened in this action. Oral arguments on the merits of the FIP challenges were held in October 2012 in the Tenth Circuit. In accordance with the court’s order, the parties have filed supplemental information.

In litigation involving several environmental groups, the United States District Court for the District of Columbia entered a consent decree, which, as amended, required EPA to issue a final rulemaking on New Mexico’s regional haze SIP by November 15, 2012. EPA approved all components of the SIP, except for the NOx BART determination for SJGS. With respect to that element of the SIP, EPA determined that with the FIP in place, it had met its obligation under the consent decree.

Because the unchanged compliance deadline of the FIP required PNM to continue to take steps to commence installation of SCRs at SJGS, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, has been suspended through November 1, 2014. 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, which amounts include costs for construction management, gross receipts taxes, AFUDC, and other PNM costs, although final costs were to be refined through an “open book” subcontractor bidding process. 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 estimates for SNCRs and the NAAQS requirements 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%.

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, subject to approval by the EIB and EPA. 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. Certain aspects of this alternative are subject to approval by the NMPRC. At June 30, 2014, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $286 million.

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.

This revised plan primarily focuses on how SJGS would meet the regional haze rule and also indicates that PNM would build a natural gas-fired generating plant in the “four corners” region to partially replace the capacity from the retired coal units. Detailed replacement power strategies also would be finalized.  PNM believes adequate replacement power alternatives will be available to meet its generation needs and ensure reliability.

It was contemplated that the retirement of SJGS Units 2 and 3 under the revised plan might result in shifts in ownership among SJGS owners or other changes in the contractual cost sharing arrangements, as would be agreed upon by the owners. See SJGS Ownership Restructuring Matters below. Owners of the affected units also may be required to seek approvals of their utility commissions or governing boards for any such changes.

The parties file periodic status reports with the Tenth Circuit.  To demonstrate that progress has been made toward settling the Tenth Circuit litigation, information, including the non-binding agreement and its accompanying timeline, was submitted to the Tenth Circuit. Following the parties’ submission of their status reports, on February 28, 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals. On October 17, 2013, the court ruled on a motion filed by PNM for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously filed motion to stay the EPA rule. The

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)

court placed the pending petitions for review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the agreement in principle fails or is not implemented as was indicated in the term sheet and timeline, any party to the litigation may file a motion seeking to lift the abatement.  PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

Due to the long lead times on certain equipment purchases, PNM began taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In April 2013, PNM issued an RFP for SNCR system design and technology. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider and in July 2014 entered into a contract for management of the SNCR construction, but has not yet entered into a construction and procurement contract.

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, including the installation of SNCRs on Units 1 and 4 and the retirement of Units 2 and 3. NMED developed a revised SIP and submitted it to the EIB for approval in May 2013. After a public hearing, the EIB approved the revised SIP in September 2013 and the revised SIP was submitted to EPA for approval on October 18, 2013. EPA deemed the SIP application complete on December 17, 2013. On April 30, 2014, EPA issued an advance copy of its proposed approval of the revised SIP and it was published in the Federal Register on May 12, 2014. EPA provided a 30 day public comment period, which ended on June 11, 2014. PNM filed comments in support of EPA’s proposed approval. Final EPA action on the revised SIP is expected by about the end of September 2014.

On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the revised SIP. 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, estimated to be approximately $205 million, 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

In its filing, PNM requested the NMPRC to issue its final ruling on the application no later than December 2014. On February 11, 2014, the Hearing Examiner issued an order finding that PNM’s application is complete. The order also stated that there was not a statutory time clock for the request to retire SJGS Units 2 and 3 and the statutory time clock on the CCN requests has not yet begun. The Hearing Examiner found that the NMPRC should proceed with the review of PNM’s application and establish a schedule that would allow NMPRC action on the application by the end of 2014.

The above estimate of PNM’s share of the costs to install SNCRs and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 includes gross receipts taxes, AFUDC, and other PNM costs. This amount and the above estimate of net book value of SJGS Units 2 and 3 at December 31, 2017 reflect the requested exchange of 78 MW of capacity out of SJGS Unit 3 and into SJGS Unit 4 resulting in PNM’s ownership share of SJGS Units 1 and 4 aggregating approximately 52%. The December 20, 2013 NMPRC filing identifies 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. See Note 12. Specific approvals to acquire other facilities 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 will 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 either SCRs or SNCRs. See Note 12 for additional information concerning PNM’s filing for NMPRC approvals regarding these matters.

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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)

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 revised SIP. 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. PNM’s ultimate ownership percentage in SJGS Unit 4 will depend on the final resolution of the negotiations among the SJGS owners and is subject to NMPRC approval. On July 1, 2014, pursuant to an order of the hearing examiner in the case, 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, which are memorialized in the resolution and term sheet described below. PNM filed testimony with the NMPRC on July 15, 2014 further describing the proposed terms. The public hearing in the NMPRC case is now scheduled to begin on October 6, 2014. PNM is currently requesting that the NMPRC take action on this case by the end of February 2015.

PNM can provide no assurance that the requirements of the plan agreed to on February 15, 2013 will be accomplished within the required timeframes or at all. If the February 15, 2013 plan is not implemented, PNM would seek to work with NMED and EPA to develop a revised timetable for implementation of the FIP. If an agreement on a revised timetable cannot be reached, PNM will likely be unable to complete the installation of SCRs on all four units at SJGS by the FIP deadline of September 21, 2016. In such event, PNM would need to rely on EPA’s pledge to work with PNM and the State of New Mexico to develop a reasonable FIP compliance plan or otherwise negotiate a solution with EPA or seek relief from the Tenth Circuit in order to continue to be able to operate the plant, including during the installation process for any alternate solution. If relief is not granted, PNM could be forced to temporarily cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire temporary replacement power through short-term or open-market purchases in order to serve the needs of its customers. There can be no assurance that sufficient replacement power will be available to serve PNM’s needs or, if available, what costs would be incurred.

PNM is unable to predict the ultimate outcome of these matters or what additional pollution control equipment will be required at SJGS.PNM will seek recovery from its ratepayers for all costs that may be incurred as a result of the CAA requirements. 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.

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. PNM is unable to predict the actions of the SJGS participants. Likewise, PNM cannot predict the impact of those actions on the ownership of SJGS or the operations of SJGS and PNM.

The SJGS participants have engaged in negotiations concerning the implementation of the revised SIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 in order to facilitate the shutdown of Units 2 and 3 to comply with the revised SIP and to accommodate the intent of the participants desiring to exit ownership in SJGS. This could have resulted in certain of the continuing participants, including PNM, acquiring additional ownership interests in Unit 4 prior to the shutdown of SJGS Units 2 and 3. Based on the status of negotiations at the time of PNM’s December 20, 2013 NMPRC filing, PNM requested NMPRC approval to exchange 78 MW of its capacity in SJGS Unit 3 for an equal amount of capacity in SJGS Unit 4. 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. The SJGS participants engaged a mediator to assist in facilitating resolution of a number of outstanding matters among the owners.

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(Unaudited)

On June 26, 2014, a non-binding resolution was unanimously approved by the SJGS Coordination Committee. 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 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. The non-binding 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. The participants continue to negotiate definitive agreements that would formalize these matters, as well as addressing plant decommissioning liabilities and indemnification. 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 proposes to acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017, rather than the exchange of 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 contemplated in the December 20, 2013 NMPRC filing. 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 Units 1 and 4 aggregating approximately 59%. PNM’s remaining replacement power plans otherwise remain as previously proposed.

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.

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, 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. The SJPPA provides that PNM, in its capacity as operating agent of SJGS, is authorized and obligated 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. On March 11, 2014, PNM requested that the owners of Unit 4 approve the expenditure of $1.9 million of costs critical to being able to comply with the time frame in the revised SIP with respect to the Unit 4 project. The Unit 4 owners did not approve the expenditures. Thereafter, PNM, as operating agent for SJGS, issued a “Prudent Utility Practice” notice under the SJPPA indicating PNM was restarting certain critical activities to keep the Unit 4 SNCR project on schedule. On June 27, 2014, PNM requested that the Unit 4 owners approve the expenditure of an additional $6.4 million of costs critical to the next phase of the Unit 4 capital project and compliance with the revised SIP deadline. The Unit 4 owners did not approve the additional expenditures. PNM subsequently issued a notice to the participants on July 14, 2014, that, consistent with “Prudent Utility Practice,” PNM must continue the work on Unit 4 and would begin to incur the additional expenditures. PNM cannot predict the outcome of this matter, its impact on SJGS’ compliance with the CAA, or the impact on PNM’s financial position, results of operations, and cash flows.

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

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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.  The deadline for comments on the draft EIS, which originally were due by the May 27, 2014, was extended to June 27, 2014.  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. PNM is unable to predict whether WEG will file a petition for rehearing or otherwise appeal the decision.

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. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

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

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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 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 stated it intends to propose a new standard. Although EPA has not announced a timeline for its review, it may release new proposed standards in the second half of 2014.  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 seek 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. In accordance with the stipulated order, PNM will repeat the mercury study required under the Consent Decree using sorbent traps instead of the monitoring system used in the initial study. 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

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(Unaudited)

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 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 voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines, 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. 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 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,

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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 voluntarily agreed to conduct similar sampling activities on the site beginning in April 2014, as well as more specific “fingerprint” analysis, which may help identify potential off-site sources. PNM is unable to predict the outcome of this matter and does not believe the former generating station is the source of the nitrates or the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made.

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. 

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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 June 30, 2014 and December 31, 2013, prepayments for coal, which are included in other current assets, amounted to $21.6 million and $12.3 million. These amounts reflect delivery of a portion of the prepaid coal and its utilization due to the mine fire incident described below. 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.

APS purchases 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 $54.6 million for the surface mines at both SJGS and Four Corners and

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

$93.3 million for the underground mine at SJGS as of June 30, 2014. At June 30, 2014 and December 31, 2013, liabilities, in current dollars, of $23.3 million and $23.8 million for surface mine reclamation and $8.2 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. It has not been decided how costs would be divided among the owners of SJGS. 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 has 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.

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.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, Delta, 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.  If the challenge to the ordinance is 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.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS 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.

(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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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). The NMPRC has scheduled a public hearing on the plan to begin September 11, 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.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

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.

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. A public hearing on the stipulation was held on February 25, 2014. The Hearing Examiner recommended approval of the settlement in its entirety to the NMPRC. 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.

Applications for Approvals to Purchase Delta

As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Report on Form 10-K, PNM entered in to an agreement to purchase 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

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(Unaudited)

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

As discussed in Note 11, on December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. In that application, PNM also sought approval to recover the net book value of SJGS Units 2 and 3 at the date of retirement, for a CCN to include PNM’s share of PVNGS Unit 3 as a resource to serve New Mexico consumers, authority to install SNCRs on SJGS Units 1 and 4, and a CCN to exchange 78 MW in SJGS Unit 3 for the same amount of capacity in SJGS Unit 4. Based upon a non-binding agreement in principle among the SJGS owners, PNM made a filing on July 1, 2014 that advised the NMPRC that it proposes to acquire an additional 132 MW of SJGS Unit 4, at no initial cost, effective December 31, 2017, rather than the exchange of 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 contemplated in its initial application. The public hearing in the NMPRC case is now scheduled to begin on October 6, 2014. PNM is currently requesting the NMPRC take action on this case by the end of February 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.

Four Corners Right of First Refusal

On June 16, 2014, PNM notified the NMPRC that it intended to provide a waiver of its right of first refusal (“ROFR”) to acquire some or all of the 7% interest in Four Corners held by EPE that is intended to be acquired by APS. On July 1, 2014, the staff of the NMPRC filed a petition asking for an inquiry by the NMPRC into whether it was in the public interest for PNM to waive its ROFR, because the cost of this capacity may be less than the cost of other resources that PNM has proposed or is considering as replacement capacity for the capacity that PNM has proposed to retire at SJGS (Note 11). The petition requested the NMPRC to initiate an inquiry, direct PNM not to waive its ROFR, and direct PNM to respond to the questions that staff attached to its petition. In its July 7, 2014 response to the staff’s petition, PNM stated that it will not file a waiver of its ROFR prior to the earlier of a NMPRC order disposing of the matter or the expiration of the 120 day period allowed for the exercise of the ROFR. The response explained that the capacity under discussion is still held by EPE, which has regulated operations in New Mexico, and EPE has not yet filed with the NMPRC for abandonment of that capacity.  The response also explained that if the Four Corners capacity was no longer an economical resource for EPE to hold, then it likely would not be an economical resource for PNM to acquire, and it would increase PNM’s dependency on coal-fired generation.  The NMPRC has not acted on the staff’s petition.

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.

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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)

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 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 2013 revenues for power sold under the Gallup contract were $2.9 million and $6.1 million in the three and 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 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 monthly 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

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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)

anticipated consumers differs from that estimate. TNMP does not expect the settlement 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 parties have agreed on terms that would resolve TNMP’s application and are preparing settlement documents for submission to the PUCT.

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 request, which is subject to PUCT approval, asks that new rates become effective on September 1, 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 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

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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)

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 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. As discussed above, these liabilities are presented as reductions of deferred tax assets for net operating loss carryforwards in the Condensed Consolidated Balance Sheets at June 30, 2014.

(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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In thousands)
Services billings:
PNMR to PNM	$	22,190	$	20,837	$	43,256	$	43,489
PNMR to TNMP	6,963		6,856		14,224		14,217
PNM to TNMP	133		133		242		241
TNMP to PNMR	—		2		—		4
Interest billings:
PNMR to TNMP	83		119		180		215
PNMR to PNM	—		—		54		1
PNM to PNMR	25		37		51		78
Income tax sharing payments:
PNMR to PNM	—		45,000		—		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 June 6, 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM.

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 749,000 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 request for additional investments in transmission assets on March 13, 2014. On July 9, 2014, TNMP filed for recovery of additional investments, which, if approved by the PUCT, would increase revenues by $4.2 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.

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

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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 interest in PVNGS Unit 3 is currently excluded from NMPRC jurisdictional rates. 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. Power generated from PNM’s 134 MW interest in PVNGS Unit 3 is currently sold into the wholesale market and any earnings or losses are attributable to shareholders. 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 percent to 13 percent.

PNMR’s long-term target is a dividend payout ratio of 50 percent to 60 percent of its ongoing earnings. Ongoing earnings, which is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP. The annual common stock dividend was raised by 16 percent in February 2012, 14 percent in February 2013, and 12 percent 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 keenly aware of the 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 top-tier electric reliability.

In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through June 30, 2014, TNMP had completed installation of more than 159,000 smart meters, which is approximately 68% of the anticipated total. TNMP’s deployment is expected to be completed in 2016.

As part of the State of Texas’ long-term initiative to create a smart electric grid, installation of smart meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. In 2014, TNMP will

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install 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. PNM also announced an agreement to purchase Delta, a 132 MW gas-fired peaking facility, which has served PNM jurisdictional needs under a 20-year PPA since 2000. The purchase was approved by the NMPRC and FERC. PNM closed on the Delta purchase on July 17, 2014.

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

• 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. 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 has set goals for even further reductions.

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 included 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 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.

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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, as amended in December 2012. 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 require 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 revised SIP from the State of New Mexico. The revised SIP has been approved by the EIB and submitted to EPA for its approval. On April 30, 2014, EPA issued an advance copy of the proposed approval of the revised SIP and it was published in the Federal Register on May 12, 2014. PNM filed comments in support of EPA’s proposed approval. Final EPA action is expected by about the end of September 2014.

Contemporaneously with the signing of the non-binding agreement, EPA indicated in writing that if the above plan does 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 new state plan.

On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the revised SIP. In this filing, PNM requested authorization 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

• Include PNM’s ownership of PVNGS Unit 3 as a resource to serve New Mexico retail customers effective January 1, 2018

• Allow cost recovery for the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4

• Exchange ownership of 78 MW of PNM’s capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4

PNM requested the NMPRC issue its final ruling on the application no later than December 2014. On February 11, 2014, PNM’s application was determined to be complete. The Hearing Examiner indicated the NMPRC should proceed with the review of PNM’s application and establish a schedule that would allow NMPRC action on the application by the end of 2014.

The December 20, 2013 filing also identifies 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. Specific approvals to acquire these facilities and the treatment of associated costs will be requested in future filings.

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 SJGS participants engaged a mediator to assist in facilitating resolution of a number of outstanding matters among the owners.

On June 26, 2014, a non-binding resolution was unanimously approved by the SJGS Coordination Committee. 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 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. Definitive agreements among the participants are being negotiated. As part of the non-binding terms, PNM confirmed that it proposes to acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017, rather than the exchange of 78 MW of

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capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 contemplated in the December 20, 2013 NMPRC filing. 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. PNM’s remaining replacement power plans otherwise remain as previously proposed.

The December 20, 2013 NMPRC filing was based on the status of negotiations among the SJGS owners at that time. On July 1, 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants pursuant to an order of the hearing examiner in the case, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS, which are memorialized in the resolution and term sheet described above. PNM filed testimony with the NMPRC on July 15, 2014 further describing the proposed terms. The public hearing in the NMPRC case is now scheduled to begin on October 6, 2014. PNM is currently requesting the NMPRC take action on this case by the end of February 2015.

A number of regulatory approvals are required to implement the proposed ownership restructuring of SJGS. Any final binding agreement or 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. The SJPPA provides that PNM is authorized and obligated to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending resolution 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. 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 revised SIP 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. PNM cannot predict the outcome of this matter.

This revised BART plan 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. PNM has begun taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider and in July 2014 entered into a contract for management of the SNCR construction, but has not yet entered into a construction and procurement contract. PNM can provide no assurance that the requirements of this plan will be accomplished at all or within the required timeframes.

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. 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 percent, SO₂ by 60 percent, particulate matter by 69 percent, and mercury by 99 percent.

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

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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, 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. Benchmark data also demonstrates positive movement in the communication component of the customer experience.

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 virtually eliminated.

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 has focused on supporting employee volunteerism, as well as customer education to address questions about the ongoing smart meter deployment. TNMP also offers energy efficiency programs specific to government buildings and schools and has successfully used the programs to improve customer relationships.

Economic Factors

In the three and six months ended June 30, 2014, PNM experienced decreases in weather normalized retail load of 3.1% and 3.0% compared to 2013.  New Mexico’s economy still lags the nation in post-recession recovery. In the three and six months ended June 30, 2014, TNMP’s weather normalized retail load increased 0.9% and 4.1% 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 June 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.

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Results of Operations

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

	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Change			2014		2013		Change
	(In millions, except per share amounts)
Net earnings attributable to PNMR	$	29.1	$	27.7	$	1.5		$	41.6	$	38.3	$	3.3
Average diluted common and common equivalent shares	80.2		80.5		(0.2		)	80.3		80.5		(0.2		)
Net earnings attributable to PNMR per diluted share	$	0.36	$	0.34	$	0.02		$	0.52	$	0.48	$	0.04

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

	Three Months Ended			Six Months Ended
	June 30, 2014			June 30, 2014
	(In millions)
PNM	$	(5.8	)	$	(9.6	)
TNMP	1.2			4.2
Corporate and Other	6.1			8.7
Net change	$	1.5		$	3.3

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, primarily in PNM’s service territory

• 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 $771.8 million at July 25, 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 $2,573.5 million for 2014-2018, including amounts expended through June 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 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.

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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 June 30,									Six Months Ended June 30,
	2014			2013			Change			2014			2013			Change
	(In millions)
Electric operating revenues	$	275.7		$	279.7		$	(4.0	)	$	538.4		$	537.6		$	0.8
Cost of energy	92.6			91.9			0.7			189.3			183.5			5.8
Margin	183.1			187.8			(4.7		)	349.1			354.1			(5.0		)
Operating expenses	106.2			103.5			2.7			214.0			206.6			7.4
Depreciation and amortization	27.0			26.1			0.9			54.1			51.9			2.2
Operating income	49.8			58.3			(8.5		)	81.1			95.5			(14.4		)
Other income (deductions)	7.6			6.2			1.4			11.4			10.3			1.1
Net interest charges	(20.0		)	(19.9		)	(0.1		)	(39.8		)	(39.8		)	—
Segment earnings before income taxes	37.4			44.6			(7.2		)	52.6			66.0			(13.4		)
Income (taxes)	(13.1		)	(14.9		)	1.8			(17.2		)	(21.5		)	4.3
Valencia non-controlling interest	(3.9		)	(3.6		)	(0.3		)	(7.4		)	(6.8		)	(0.6		)
Preferred stock dividend requirements	(0.1		)	(0.1		)	—			(0.3		)	(0.3		)	—
Segment earnings	$	20.2		$	26.0		$	(5.8	)	$	27.8		$	37.4		$	(9.6	)

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

	2013/2014 Change
	Three Months Ended June 30,									Six Months Ended June 30,
	Electric									Electric
	Operating			Cost of						Operating			Cost of
	Revenues			Energy			Margin			Revenues			Energy			Margin
	(In millions)
Customer usage/load	$	(2.0	)	$	—		$	(2.0	)	$	(6.5	)	$	—		$	(6.5	)
Weather	(2.4		)	—			(2.4		)	(5.8		)	—			(5.8		)
Economy service	1.8			1.8			—			4.5			4.4			0.1
Wholesale rate increases	0.4			—			0.4			0.9			—			0.9
Renewable energy rider	1.1			(0.3		)	1.4			5.6			2.0			3.6
Energy efficiency rider	1.4			—			1.4			1.4			—			1.4
Unregulated margin	0.7			—			0.7			2.3			(2.1		)	4.4
Net unrealized economic hedges	(3.8		)	(0.3		)	(3.5		)	(0.8		)	0.6			(1.4		)
Other	(1.2		)	(0.5		)	(0.7		)	(0.8		)	0.9			(1.7		)
Net change	$	(4.0	)	$	0.7		$	(4.7	)	$	0.8		$	5.8		$	(5.0	)

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2014			2013		Change			2014			2013			Change
	(In millions, except customers)
Residential	$	92.7		$	92.6	$	0.1		$	190.4		$	196.9		$	(6.5	)
Commercial	109.2			112.1		(2.9		)	198.9			200.3			(1.4		)
Industrial	17.3			19.2		(1.9		)	33.1			36.6			(3.5		)
Public authority	6.0			6.5		(0.5		)	11.2			11.8			(0.6		)
Economy service	10.0			8.2		1.8			20.6			16.1			4.5
Other retail	1.7			2.4		(0.7		)	5.2			5.8			(0.6		)
Transmission	9.7			9.3		0.4			18.8			18.0			0.8
Firm-requirements wholesale	10.4			9.4		1.0			21.9			20.9			1.0
Other sales for resale	19.1			16.6		2.5			41.7			33.7			8.0
Mark-to-market activity	(0.4		)	3.4		(3.8		)	(3.4		)	(2.5		)	(0.9		)
	$	275.7		$	279.7	$	(4.0	)	$	538.4		$	537.6		$	0.8
Average retail customers (thousands)	510.8			507.8		3.0			510.6			507.6			3.0

The following table shows GWh sales by customer class:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014	2013	Change		2014	2013	Change
	(Gigawatt hours)
Residential	731.2	735.9	(4.7	)	1,506.2	1,587.2	(81.0	)
Commercial(1)	1,005.2	1,055.5	(50.3	)	1,873.2	1,933.9	(60.7	)
Industrial	242.7	274.2	(31.5	)	482.6	526.8	(44.2	)
Public authority	63.1	71.6	(8.5	)	114.7	126.6	(11.9	)
Economy service	192.1	176.9	15.2		383.6	353.6	30.0
Firm-requirements wholesale	149.4	150.1	(0.7	)	310.2	327.3	(17.1	)
Other sales for resale	539.0	495.4	43.6		1,122.9	1,028.1	94.8
	2,922.7	2,959.6	(36.9	)	5,793.4	5,883.5	(90.1	)

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

For the three and six months ended June 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 in the first quarter of 2014, the unemployment rate decreased from 7.0% to 6.5% in the second quarter.  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 3.1% and 3.0% lower for the three and six months ended June 30, 2014 compared to 2013, which decreased revenues and margin $2.0 million and $6.5 million for the three and six months ended June 2014. Weather negatively impacted revenues and margin $2.4 million and $5.8 million during the three and six months ended June 30, 2014 compared to 2013. Cooling degree days were 13.0% lower for the three and six months ended June 30, 2014 compared to the same period in 2013 and heating degree days were 8.8% lower year to date 2014 compared to 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 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 $0.4 million and $0.9 million for the three and six months ended June 30, 2014 compared to 2013. After undertaking a request for proposal process, 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

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for power sold under the Gallup contract were $2.9 million and $6.1 million in the three and six months ended June 30, 2014 and totaled $11.7 million during 2013. See Note 12.

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 six months ended June 30, 2014, this rider increased revenues by $1.1 million and $5.6 million. These revenues include a return on investment of $1.2 million and $2.5 million for the three and six months ended June 30, 2014 compared to $0.8 million and $1.5 million for the three and six months ended June 30, 2013. Cost of energy, reflecting purchase of RECs, decreased $0.3 million for the three months ended June 30, 2014 and increased $2.0 million for the six months ended June 30, 2014. Revenue and margin from PNM’s energy efficiency rider increased $1.4 million for the three months and six months ended June 30, 2014. Revenues from these riders also recover incremental operating, depreciation, and interest expenses applicable to these programs.

For the three and six months ended June 30, 2014, unregulated revenue increased $0.7 million and $2.3 million and unregulated margin increased $0.7 million and $4.4 million. Higher market power prices for PVNGS Unit 3 increased revenues and margins by $0.7 million and $2.3 million for the three and six months ended June 30, 2014 compared to 2013. In addition, gas imbalance settlements lowered cost of energy $2.1 million for the six months ended June 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 losses of $0.4 million for the three months ended June 30, 2014 compared to unrealized gains of $3.1 million for the three months ended June 30, 2013, decreased margin by $3.5 million. Unrealized losses of $3.2 million for the six months ended June 30, 2014 compared to unrealized losses of $1.8 million for the six months ended June 30, 2013, decreased margin by $1.4 million.

PNM provides economy energy services to a major customer. Although KWh sales to this customer increased for the three and six months ended June 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.

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 discussed in Note 12, the NMPRC approved the continuation of PNM’s FPPAC in April 2014. As part of that approval, beginning July 1, 2013, PNM retains 10% of the revenue from off-system sales that would otherwise be passed through the FPPAC. PNM recorded revenue of $1.2 million, which includes amounts from July 1, 2013 through June 30, 2014, during the three months ended June 30, 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 June 30, 2014, operating expenses increased $2.7 million compared to 2013. In the three months ended June 30, 2014, lower maintenance expenses for outages at San Juan and Four Corners of $1.9 million and $1.0 million were partially offset by higher maintenance expenses of $1.0 million at PVNGS and $0.3 million at natural gas-fired plants. Process improvement initiatives increased operating expense $1.8 million for the three months ended June 30, 2014 compared to 2013. Higher energy efficiency expenses of $1.3 million, which are recovered through rider revenue as described above, increased operating expenses for the three months ended June 30, 2014 compared to 2013. In addition, higher property taxes of $0.9 million due to increased plant in service and higher assessed property values and higher pension and retiree medical expenses of $0.2 million increased operating expense for the three months ended June 30, 2014 compared to 2013.

For the six months ended June 30, 2014, operating expenses increased $7.4 million compared to 2013. In the six months ended June 30, 2014, lower maintenance expenses for outages at San Juan and Four Corners of $0.5 million and $0.2 million were more than offset by higher maintenance expenses of $0.5 million at PVNGS and $1.3 million at natural gas-fired plants. Process improvement initiatives increased operating expense $1.8 million for the six months ended June 30, 2014 compared to 2013. Higher energy efficiency expenses and renewable rider expenses of $1.2 million and $0.5 million, which are recovered through rider revenue, increased operating expenses for the six months ended June 30, 2014. Higher property taxes due to increased plant in service and higher assessed property values increased operating expenses $1.8 million for the six months ended June 30, 2014 compared to 2013. In addition, higher pension and retiree medical of $0.5 million and higher bad debt expense of $0.7 million increased operating expense for the six months ended June 30, 2014 compared to 2013.

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Depreciation and amortization expense increased $0.9 million and $2.2 million for the three and six months ended June 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) increased $1.4 million and $1.1 million for the three and six months ended June 30, 2014 compared to 2013. Lower interest income on PVNGS lessor notes of $0.5 million and $1.0 million due to lower outstanding balances decreased interest income for the three and six months ended June 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 increased $1.5 million and $2.5 million for the three and six months ended June 30, 2014 compared to 2013.

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. As a result of the settlement PNM recorded an additional income tax expense of $1.1 million in the three months ended June 30, 2014. This amount includes an offset of an income tax benefit of $1.3 million reflected in the Corporate and Other segment.

TNMP

The following table summarizes the operating results for TNMP:

	Three Months Ended June 30,									Six Months Ended June 30,
	2014			2013			Change			2014			2013			Change
	(In millions)
Electric operating revenues	$	70.5		$	67.9		$	2.6		$	136.6		$	127.7		$	8.9
Cost of energy	16.8			13.8			3.0			32.8			26.9			5.9
Margin	53.7			54.1			(0.4		)	103.8			100.8			3.0
Operating expenses	20.4			22.2			(1.8		)	41.5			44.1			(2.6		)
Depreciation and amortization	12.0			12.3			(0.3		)	23.8			24.0			(0.2		)
Operating income	21.3			19.7			1.6			38.5			32.7			5.8
Other income (deductions)	0.5			0.5			—			0.7			0.7			—
Net interest charges	(6.7		)	(6.8		)	0.1			(13.3		)	(14.0		)	0.7
Segment earnings before income taxes	15.1			13.4			1.7			26.0			19.4			6.6
Income (taxes)	(5.6		)	(5.1		)	(0.5		)	(9.6		)	(7.3		)	(2.3		)
Segment earnings	$	9.5		$	8.3		$	1.2		$	16.3		$	12.1		$	4.2

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 June 30,								Six Months Ended June 30,
	Electric								Electric
	Operating			Cost of					Operating			Cost of
	Revenues			Energy		Margin			Revenues			Energy		Margin
	(In millions)
Rate increases	$	1.5		$	—	$	1.5		$	3.0		$	—	$	3.0
Customer usage/load	0.1			—		0.1			0.6			—		0.6
Customer growth	0.4			—		0.4			0.7			—		0.7
Weather	(0.4		)	—		(0.4		)	0.1			—		0.1
Recovery of third-party transmission costs	3.0			3.0		—			5.9			5.9		—
AMS surcharge	0.3			—		0.3			1.2			—		1.2
CTC surcharge	—			—		—			0.4			—		0.4
Hurricane Ike surcharge	(1.4		)	—		(1.4		)	(2.6		)			(2.6		)
Other	(0.9		)	—		(0.9		)	(0.4		)	—		(0.4		)
Net change	$	2.6		$	3.0	$	(0.4	)	$	8.9		$	5.9	$	3.0

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014		2013		Change		2014		2013		Change
	(In millions, except consumers)
Residential	$	26.1	$	24.8	$	1.3	$	52.9	$	47.7	$	5.2
Commercial	25.3		24.9		0.4		48.4		45.8		2.6
Industrial	3.8		3.4		0.4		7.2		6.4		0.8
Other	15.3		14.8		0.5		28.1		27.8		0.3
	$	70.5	$	67.9	$	2.6	$	136.6	$	127.7	$	8.9
Average consumers (thousands) (1)	237.4		234.7		2.7		237.0		234.4		2.6

⁽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 June 30,				Six Months Ended June 30,
	2014	2013	Change		2014	2013	Change
	(Gigawatt hours)
Residential	647.0	651.2	(4.2	)	1,289.1	1,212.6	76.5
Commercial	655.1	661.2	(6.1	)	1,195.2	1,139.5	55.7
Industrial	669.0	681.7	(12.7	)	1,317.1	1,234.2	82.9
Other	25.9	28.3	(2.4	)	49.4	49.7	(0.3	)
	1,997.0	2,022.4	(25.4	)	3,850.8	3,636.0	214.8

For the three and six months ended June 30, 2014, revenues and margin increased by $1.5 million and $3.0 million compared to 2013 due to transmission rate increases in March 2013, September 2013, and March 2014. See Note 12. TNMP experienced positive year to date average customer growth of 1.1%, increasing revenues and margin by $0.4 million and $0.7 million for the three and six months ended June 30, 2014 compared to 2013. Higher weather normalized usage per customer increased revenues an

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d margin by $0.1 million and $0.6 million for the three and six months ended June 30, 2014 compared to 2013. TNMP’s weather normalized retail KWh sales increased 0.9% and 4.1% for the three and six months ended June 30, 2014 compared to 2013. Milder weather in the three months ended June 30, 2014 decreased revenues and margins by $0.4 million, but weather for the six months ending June 30, 2014 increased revenues and margins by $0.1 million. For the three and six months ended June 30, 2014 compared to 2013, heating degree days were down 37.9% and 21.9% higher, which was offset by cooling degree days being flat and 2.5% lower. 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 quarter.

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 $3.0 million and $5.9 million for the three and six months ended June 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 $3.0 million and $5.9 million for the three and six months ended June 30, 2014 compared to 2013.

The AMS surcharge increased revenues and margin by $0.3 million and $1.2 million for the three and six months ended June 30, 2014 compared to 2013. The CTC surcharge had only minor impacts to revenues and margins for the three months ended June 30, 2014 compared to 2013 and increased revenues and margin by $0.4 million for the six months ended June 30, 2014 compared to 2013. The Hurricane Ike surcharge decreased revenues and margin by $1.4 million and $2.6 million for the three and six months ended June 30, 2014 compared to 2013. Other revenues, which include recovery of rate case expenses and energy efficiency programs were lower for the three and six months ended June 30, 2014 compared to 2013. Changes in revenues and margins from all of these surcharges are offset by changes in operating expenses and depreciation and amortization. The Hurricane Ike surcharge was terminated in November of 2013 and the rate case surcharge was terminated in April of 2014 due to full recovery of costs associated with these items.

Operating expenses decreased $1.8 million and $2.6 million for the three and six months ended June 30, 2014 compared to 2013. Lower employee healthcare claims of $0.4 million and $0.9 million and lower property and casualty claims of $0.3 million and $0.4 million decreased operating expense for the three and six months ended June 30, 2014 compared to 2013. Higher capitalization of administrative and general expenses related to construction projects improved operating expenses by $0.9 million and $1.0 million for the three and six months ended June 30, 2014 compared to 2013. Lower vegetation management costs of $0.1 million and $0.3 million decreased operating expenses in the three and six months ended June 30, 2014 compared to 2013.

Depreciation and amortization decreased $0.3 million and $0.2 million for the three and six months ended June 30, 2014 compared to 2013. Depreciation expense associated with the AMS deployment, which is recovered through the AMS surcharge, increased $0.5 million and $1.0 million for the three and six months ended June 30, 2014 compared to 2013. Amortization expense associated with the CTC, which is recovered through the CTC surcharge, increased $0.1 million and $0.5 million for the three and six months ended June 30, 2014 compared to 2013. In addition, an increase in utility plant in service increased depreciation by $0.3 million and $0.7 million for the three and six months ended June 30, 2014 compared to 2013. These increases are offset by lower amortization of the Hurricane Ike costs of $1.2 million and $2.3 million for the three and six months ended June 30, 2014 compared to 2013.

Interest charges decreased $0.7 million for the six months ended June 30, 2014 compared to 2013. The decrease primarily results from 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.

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Corporate and Other

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

	Three Months Ended June 30,									Six Months Ended June 30,
	2014			2013			Change			2014			2013			Change
	(In millions)
Total revenues	$	—		$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—			—
Margin	—			—			—			—			—			—
Operating expenses	(3.4		)	(3.2		)	(0.2		)	(6.6		)	(6.9		)	0.3
Depreciation and amortization	3.1			3.3			(0.2		)	6.2			6.6			(0.4		)
Operating income (loss)	0.2			(0.1		)	0.3			0.4			0.3			0.1
Other income (deductions)	(0.3		)	(2.2		)	1.9			(1.0		)	(4.0		)	3.0
Net interest charges	(3.3		)	(4.0		)	0.7			(6.4		)	(8.1		)	1.7
Segment earnings (loss) before income taxes	(3.4		)	(6.3		)	2.9			(7.0		)	(11.8		)	4.8
Income (taxes) benefit	2.8			(0.3		)	3.1			4.5			0.6			3.9
Segment earnings (loss)	$	(0.6	)	$	(6.7	)	$	6.1		$	(2.5	)	$	(11.2	)	$	8.7

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

During the three and six months ended June 30, 2013, income (taxes) benefit for Corporate and Other included the impairment of New Mexico wind energy production tax credits of $2.4 million and $3.9 million, after federal income tax benefits. In addition, the three months ended June 30, 2013 included 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. As a result of the settlement an income tax benefit of $1.3 million was reflected in Corporate and Other in the three months ended June 30, 2014. This amount is offset by an additional income tax expense reflected in the PNM segment.

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LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

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

	Six Months Ended June 30,
	2014			2013			Change
	(In millions)
Net cash flows from:
Operating activities	$	123.8		$	159.9		$	(36.1	)
Investing activities	(151.1		)	(143.1		)	(8.0		)
Financing activities	36.9			9.0			27.9
Net change in cash and cash equivalents	$	9.6		$	25.8		$	(16.2	)

The decreases in PNMR’s cash flow from operating activities relate primarily to $92.9 million lower tax refunds in 2014 than in 2013 offset by $61.1 million lower contributions to the PNM and TNMP pension and OPEB plans in 2014 than in 2013. In addition, refunds of $15.2 million made to customers related to the settlement of PNM’s transmission rate in 2013 did not recur in 2014. Other changes in assets and liabilities resulting from normal operations as well as higher retail load and rate increases at TNMP increased operating cash flows. These increases were offset by lower retail load at PNM.

The changes in PNMR’s cash flows from investing activities relate primarily to an increase of $7.4 million in utility plant additions in the three months ended June 30, 2014 compared to 2013. Utility plant additions at PNM were $6.1 million lower in the six months ended June 30, 2014 compared to 2013, including decreases in generation and renewable energy additions of $18.6 million and $3.3 million. These decreases were offset by increased transmission and distribution additions of $15.8 million and higher nuclear fuel purchases of $0.6 million. TNMP utility plant additions increased $17.1 million in the six months ended June 30, 2014 compared to 2013, including increases in transmission and distribution additions of $11.3 million and AMS additions of $5.8 million. Corporate plant additions decreased $3.6 million related to computer hardware and software additions and payments made in 2013 for renovations of the corporate headquarters building.

The changes in PNMR’s cash flows from investing activities include a $45.5 million reduction in net short-term borrowing activity in the six months ended June 30, 2014 compared to 2013. In 2014, the proceeds from long-term borrowings of $175.0 million at PNM were used to repay amounts under the PNM Term Loan Agreement and other short-term borrowings. Long-term borrowings of $80.0 at TNMP in 2014 were used to repay amounts under the existing TNMP 2011 Term Loan Agreement and other short-term borrowings. In addition, cash paid of $13.0 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 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

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conditions. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.10% at June 30, 2014, and must be repaid on or before September 4, 2015. At June 30, 2014, the weighted average interest rate was 1.00% 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 (the “Series 2014A Bonds”) 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 June 30, 2014, are:

	2014		2015-2018		Total
	(In millions)
Construction expenditures	$	509.3	$	1,766.9	$	2,276.2
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	$	2,004.8	$	2,573.5

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 Delta. 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 six months ended June 30, 2014, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements and the PNM 2014 Term Loan 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 that becomes due in the second 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 $12.1 million during the three months ended June 30, 2014 and from zero to $21.1 million during the six months ended June 30, 2014. Borrowings under the PNM Revolving Credit Facility ranged from zero to $8.2 million during the three months ended June 30, 2014 and from zero to $82.0 million during the six months ended June 30, 2014. PNM had no borrowings under the PNM New Mexico Credit Facility during the three months ended June 30, 2014, and borrowings ranged from zero to $25.0 million during the six months ended June 30, 2014. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $30.0 million during the three and six months ended June 30, 2014. At June 30, 2014, the average interest rate was 1.66% for borrowings under the PNMR Revolving Credit Facility. The PNM Revolving Credit Facility and the TNMP Revolving Credit Facility had no borrowings outstanding at June 30, 2014.

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 July 25, 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 July 25, 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 July 25, 2014:
Revolving credit facility	$	—	$	27.2	$	—	$	27.2
PNM New Mexico Credit Facility	—		15.0		—		15.0
Letters of credit	7.7		3.2		0.1		11.0
Total short-term debt and letters of credit	7.7		45.4		0.1		53.2
Remaining availability as of July 25, 2014	$	292.3	$	404.6	$	74.9	$	771.8
Invested cash as of July 25, 2014	$	1.9	$	—	$	—	$	1.9

The above table excludes intercompany debt. As of July 25, 2014, PNM had $5.5 million in borrowings from PNMR 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, the EIP transmission line, and Delta. These arrangements help ensure PNM the availability of lower-cost generation needed to serve customers. 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 Delta.

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.

	June 30, 2014		December 31, 2013
PNMR
PNMR common equity	47.4	%	48.8	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	52.3	%	50.9	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	47.0	%	48.2	%
Preferred stock	0.4	%	0.4	%
Long-term debt	52.6	%	51.4	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	58.3	%	59.9	%
Long-term debt	41.7	%	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 36 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, wh

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ich 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 percent at SJGS. That agreement also contemplates that gas-fired generation would be built to partially replace the retired capacity. Although replacement power strategies have not been finalized, the reduction in GHG from the retirement of the coal-fired generation would be far greater than the increase in GHG from replacement with gas-fired generation. On September 5, 2013, the EIB unanimously approved a revised SIP submitted by NMED that encompassed the February 15, 2013 agreement and the revised SIP was submitted to EPA for approval on October 18, 2013. On May 12, 2014, EPA published their proposed approval of the revised SIP in the Federal Register. Final EPA action on the revised SIP is expected by about the end of September 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

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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.

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 will be reviewing 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.”

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.

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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 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 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.

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.

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. PNM estimates that implementation of the revised SIP 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 a revised SIP 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, 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 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.

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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 Company monitors international treaties and accords such as the Kyoto Protocol and the EU Emissions Trading System to determine potential impacts to their business activities.  At the United Nations Framework Convention on Climate Change 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.

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

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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. 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. The retirement and changes to these MOD standards will remove the risk of reduced TTC for PNM and other southwestern utilities. On June 19, 2014, FERC issued a NOPR to approve a new reliability standard.

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.

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 recordkeeping 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

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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 June 30, 2014, TNMP had 187 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 June 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. 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 recovery of the net book value of SJGS Units 2 and 3 at the date of their proposed early retirement as contemplated in the revised SIP 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 approval of the revised SIP 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

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• 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 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

• 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.”

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.

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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

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 six months ended June 30, 2014 and the year ended December 31, 2013, PNMR and PNM 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.

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	Six Months Ended
	June 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	1,043			(964		)
Changes in fair value	(4,230		)	(841		)
Net mark-to-market change recorded in earnings	(3,187		)	(1,805		)
Net change recorded as regulatory assets and liabilities	(477		)	512
Net fair value at end of period	$	(391	)	$	(89	)

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 June 30, 2014

	Settlement Dates
	2014			2015		2016
	(In thousands)
Economic hedges
Prices actively quoted	$	—		$	—	$	—
Prices provided by other external sources	(2,512		)	2,464		(343		)
Prices based on models and other valuations	—			—		—
Total	$	(2,512	)	$	2,464	$	(343	)

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 six months ended June 30, 2014, the high, low, and average VaR amounts were $1.1 million, $0.6 million, and $0.7 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 June 30, 2014 and December 31, 2013, the VaR amounts for the PNM wholesale portfolio were $1.1 million and $0.6 million.

The VaR limits, which were not exceeded during the six months ended June 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 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

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by the credit worthiness (credit rating) and concentration of credit risk for counterparties to derivative transactions. All credit exposures at June 30, 2014 will mature in less than two years.

Schedule of Credit Risk Exposure

June 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	$	8,395	1	$	7,671
Non-investment grade	—		—	—
Internal ratings:
Investment grade	103		—	—
Non-investment grade	113		—	—
Total	$	8,611		$	7,671

⁽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 June 30, 2014, PNMR held $0.1 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of June 30, 2014 was $7.7 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 2.2%, or $46.0 million, if interest rates were to decline by 50 basis points from their levels at June 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 July 25, 2014, PNMR, PNM, and TNMP had zero, $27.2 million, and zero of 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 $15.0 million in borrowings under its $50.0 million PNM New Mexico Credit Facility at July 25, 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 at variable rates, which averaged 1.41% for the PNM Revolving Credit Facility, 1.41% for the PNM New Mexico Credit Facility, 1.00% for the PNMR Term Loan Agreement, and 1.10% for the PNM 2014 Term Loan Agreement on July 25, 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 $236.4 million at June 30, 2014, of which 41.1% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at June 30, 2014, the decrease in the fair value of the fixed-rate securities would be 3.3%, or $3.2 million.

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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 June 30, 2014. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 57.6% of the securities held by various trusts as of June 30, 2014. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $13.6 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 June 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

• 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

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Note 12

• PNM – Renewable Portfolio Standard

• PNM – FPPAC Continuation Application

• PNM – Integrated Resource Plan

• PNM – Applications for Approvals to Purchase Delta

• PNM – Application for Approval of La Luz Generating Station

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

• PNM – Four Corners Right of First Refusal

• 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.

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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)
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:	August 1, 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-12.1

Exhibit 12.1
PNM RESOURCES, INC. AND SUBSIDIARIES
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)
	Six Months Ended			Year Ended December 31,
	June 30, 2014			2013				2012			2011				2010				2009
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	57,752		$	118,880			$	125,379		$	122,998			$	123,633			$	123,833
Amortization of debt premium, discount, and expenses	1,882			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	2,879			5,847				5,585			6,665				6,888				7,034
Preferred dividend requirements of subsidiary	383			800				769			864				1,075				759
Total Fixed Charges	$	62,896		$	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	$	71,625		$	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	71,625			175,069				175,035			321,469				(48,156		)		124,896
Fixed charges as above	62,896			129,243				135,756			134,222				136,223				138,083
Interest capitalized	(2,772		)	(5,209		)		(5,432		)	(2,697		)		(3,401		)		(7,743		)
Non-controlling interest in earnings of Valencia	(7,439		)	(14,521		)		(14,050		)	(14,047		)		(13,563		)		(11,890		)
Preferred dividend requirements of subsidiary	(383		)	(800		)		(769		)	(864		)		(1,075		)		(759		)
Earnings Available for Fixed Charges	$	123,927		$	283,782			$	290,540		$	438,083			$	70,028			$	242,587
Ratio of Earnings to Fixed Charges	1.97			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)
	Six Months Ended			Year Ended December 31,
	June 30, 2014			2013				2012			2011				2010			2009
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	39,778		$	79,769			$	82,864		$	75,217			$	73,423		$	73,104
Amortization of debt premium, discount and expenses	977			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	1,761			3,732				3,743			4,139				4,103			4,517
Total Fixed Charges	$	42,516		$	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	$	52,649		$	151,480			$	156,314		$	105,965			$	107,288		$	45,627
Fixed charges as above	42,516			85,380				88,425			80,681				78,800			79,984
Non-controlling interest in earnings of Valencia	(7,439		)	(14,521		)		(14,050		)	(14,047		)		(13,563		)	(11,890		)
Interest capitalized	(2,345		)	(4,420		)		(4,314		)	(1,761		)		(2,811		)	(6,067		)
Earnings Available for Fixed Charges	$	85,381		$	217,919			$	226,375		$	170,838			$	169,714		$	107,654
Ratio of Earnings to Fixed Charges	2.01			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)
	Six Months Ended			Year Ended December 31,
	June 30, 2014			2013			2012			2011				2010			2009
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	11,700		$	24,481		$	26,233		$	27,914			$	28,632		$	25,609
Amortization of debt premium, discount and expenses	578			1,159			1,493			1,679				2,683			3,355
Estimated interest factor of lease rental charges	629			1,241			956			1,202				1,246			831
Total Fixed Charges	$	12,907		$	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	$	25,976		$	46,711		$	42,099		$	36,138			$	26,026		$	20,151
Fixed charges as above	12,907			26,881			28,682			30,795				32,561			29,795
Interest capitalized	(244		)	(361		)	(706		)	(593		)		(158		)	(1,144		)
Earnings Available for Fixed Charges	$	38,639		$	73,231		$	70,075		$	66,340			$	58,429		$	48,802
Ratio of Earnings to Fixed Charges	2.99			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:	August 1, 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:	August 1, 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:	August 1, 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:	August 1, 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:	August 1, 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:	August 1, 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 June 30, 2014, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on August 1, 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:	August 1, 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 June 30, 2014, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on August 1, 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:	August 1, 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 June 30, 2014, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on August 1, 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:	August 1, 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

XML

Lease Commitments (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2014 Public Service Company of New Mexico [Member]	Jun. 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	Jun. 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	31.2494
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

XML

Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Service billings [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 0	$ 2	$ 0	$ 4
Service billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	22,190	20,837	43,256	43,489
Service billings [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	6,963	6,856	14,224	14,217
Service billings [Member] | PNM to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	133	133	242	241
Interest charges [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	54	1
Interest charges [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	83	119	180	215
Interest charges [Member] | PNM to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	25	37	51	78
Income tax sharing payments [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	45,000	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

XML

Financing, Financing Activities (Details) (USD $)												3 Months Ended			3 Months Ended
	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014 Public Service Company of New Mexico [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member]	Jun. 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]	Jun. 30, 2014 PNMR Term Loan Agreement [Member]	Dec. 31, 2013 PNMR Term Loan Agreement [Member]	Jun. 30, 2014 PNM 2014 Term Loan Agreement [Member] Public Service Company of New Mexico [Member]	Mar. 05, 2014 PNM 2014 Term Loan Agreement [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 2011 Term Loan Agreement, First Mortgage Bonds Due 2014 [Member] Texas-New Mexico Power Company [Member]	Dec. 09, 2013 Bonds [Member] First Mortgage Bonds Due 2024, Series 2014A, at 4 point 03 percent [Member] [Member] Texas-New Mexico Power Company [Member]	Mar. 06, 2013 First Mortgage Bonds [Member] First Mortgage Bonds, due 2043, Series 2013A [Member] Texas-New Mexico Power Company [Member]	Jun. 30, 2014 Notes Payable to Banks [Member] Texas-New Mexico Power Company [Member]	Apr. 22, 2013 Notes Payable to Banks [Member] PNM Term Loan Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt											$ 175,000,000
Debt Instrument, Face Amount													80,000,000
Debt Instrument, Interest Rate, Stated Percentage													4.03%
Proceeds from Bank Debt												50,000,000			30,000,000
Debt Instrument, Cash for Bond Exchange Conversion														0.14
Short-term debt	105,000,000	149,200,000	0	49,200,000	0		0	100,000,000	100,000,000							75,000,000
Debt Instrument, Interest Rate at Period End										1.10%
Debt Instruments, NMPRC Approved credit facility						$ 50,000,000

XML

Goodwill (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Jun. 30, 2014 Public Service Company of New Mexico [Member]	Apr. 01, 2014 Public Service Company of New Mexico [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member]	Apr. 01, 2013 Public Service Company of New Mexico [Member]	Jun. 30, 2014 Texas-New Mexico Power Company [Member]	Dec. 31, 2013 Texas-New Mexico Power Company [Member]	Apr. 01, 2012 Texas-New Mexico Power Company [Member]
Goodwill [Line Items]
Goodwill	$ 278,297	$ 278,297	$ 278,297	$ 51,632	$ 51,600	$ 51,632		$ 226,665	$ 226,665	$ 226,700
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount					30.00%		27.00%			26.00%

XML

Stock-Based Compensation (Details) (USD $)	6 Months Ended			6 Months Ended					1 Months Ended				6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Jun. 30, 2014 Stock Options [Member]	Jun. 30, 2014 Restricted Stock [Member]	Jun. 30, 2013 Restricted Stock [Member]	Jun. 30, 2014 Market-Based Shares [Member]	Jun. 30, 2013 Market-Based Shares [Member]	Feb. 28, 2014 Executive [Member] Performance Shares [Member]	Jun. 30, 2014 Executive [Member] Performance Shares [Member]	Mar. 31, 2012 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] Chairman, President, and Chief Executive Officer [Member]	Mar. 31, 2012 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] Chairman, President, and Chief Executive Officer [Member]	Jun. 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	$ 7,700,000		$ 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	(236,260)
Options, Exercised, Weighted-Average Exercise Price (in dollars per share)	$ 18.90
Options, Forfeited, Shares	(17,151)
Options, Forfeited, Weighted-Average Exercise Price (in dollars per share)	$ 26.43
Options, Expired, Shares	(22,784)
Options, Expired, Weighted-Average Exercise Price (in dollars per share)	$ 25.91
Options, Outstanding at end of period, Shares	1,067,471
Options, Outstanding at end of period, Weighted-Average Exercise Price (in dollars per share)	$ 20.80
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					(292,052)
Nonvested Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 16.64
Nonvested Restricted Stock, Forfeited, Shares					0
Nonvested Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value (in dollars per share)					$ 0.00
Nonvested Restricted Stock, Nonvested at end of period, Shares					265,417
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				9,400,000
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years)				3 years 2 months 13 days
Options, Outstanding at end of period, No intrinsic value	297,350
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	1,779,000	2,189,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Total fair value of shares that vested					$ 4,854,000	$ 4,383,000
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%

XML

Related Party Transactions (Tables)

6 Months Ended

Jun. 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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In thousands)
Services billings:
PNMR to PNM	$	22,190	$	20,837	$	43,256	$	43,489
PNMR to TNMP	6,963		6,856		14,224		14,217
PNM to TNMP	133		133		242		241
TNMP to PNMR	—		2		—		4
Interest billings:
PNMR to TNMP	83		119		180		215
PNMR to PNM	—		—		54		1
PNM to PNMR	25		37		51		78
Income tax sharing payments:
PNMR to PNM	—		45,000		—		45,000
PNMR to TNMP	—		—		—		—

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Earnings Per Share (Tables)

6 Months Ended

Jun. 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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	29,141	$	27,678	$	41,609	$	38,304
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	110		194		146		202
Average Shares – Basic	79,764		79,848		79,800		79,856
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	464		607		508		661
Average Shares – Diluted	80,228		80,455		80,308		80,517
Net Earnings Per Share of Common Stock:
Basic	$	0.37	$	0.35	$	0.52	$	0.48
Diluted	$	0.36	$	0.34	$	0.52	$	0.48

⁽¹⁾  Excludes the effect of out-of-the-money options for 297,350 shares of common stock at June 30, 2014.

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Commitments and Contingencies (Commitments and Contingencies Related to the Environment) (Details) (USD $)							12 Months Ended													0 Months Ended					6 Months Ended									6 Months Ended
	Dec. 21, 2011 mw	Dec. 21, 2011 San Juan Generating Station [Member]	Oct. 31, 2012 Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] San Juan Generating Station Units 2 and 3 [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]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member]	Jun. 30, 2014 PNM Electric [Member] San Juan Generating Station Units 2 and 3 [Member]	Jun. 30, 2014 PNMR and PNM [Member] Palo Verde Nuclear Generating Station Unit 3 [Member] MW	Jun. 30, 2014 Other Deferred Credits [Member] Public Service Company of New Mexico [Member] Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member]	Dec. 31, 2013 Other Deferred Credits [Member] Public Service Company of New Mexico [Member] Nuclear Spent Fuel And Waste Disposal [Member] Palo Verde Nuclear Generating Station [Member]	Jun. 30, 2014 Clean Air Act related to Regional Haze [Member] state	Jun. 30, 2014 Clean Air Act Related to Post Combustion Controls [Member] Public Service Company of New Mexico [Member] Four Corners [Member]	Aug. 06, 2012 Clean Air Act Related to Post Combustion Controls [Member] Public Service Company of New Mexico [Member] Four Corners [Member] compliance_alternative	Jun. 30, 2014 Clean Air Act Related to Post Combustion Controls [Member] Public Service Company of New Mexico [Member] Four Corners Units 4 and 5 (Coal) [Member]	Dec. 20, 2013 Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member] MW	Jun. 30, 2014 Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station Unit 3 [Member]	Dec. 20, 2013 Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station Unit 3 [Member] MW	Dec. 20, 2013 Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station Units 2 and 3 [Member] MW	Jun. 30, 2014 Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member]	Jun. 26, 2014 Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member] MW	Dec. 20, 2013 Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member] MW	Dec. 20, 2013 Clean Air Act, SNCR [Member] PNMR and PNM [Member] Palo Verde Nuclear Generating Station Unit 3 [Member] MW	Jun. 30, 2014 Mercury Control [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jun. 30, 2014 Environmental Protection Agency [Member] WildEarth Guardians filed an action to challenge EPA's rule in the Tenth Circuit [Member] San Juan Generating Station [Member]	Jun. 30, 2014 Environmental Protection Agency [Member] Clean Air Act Related to Post Combustion Controls [Member] Public Service Company of New Mexico [Member] Four Corners [Member]	Jun. 27, 2014 Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member]	Mar. 11, 2014 Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station Unit 4 [Member]	Jan. 31, 2010 Minimum [Member] Public Service Company of New Mexico [Member] San Juan Generating Station And Four Corners [Member] opp	Oct. 31, 2012 Minimum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Clean Air Act, SCR [Member] [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Oct. 31, 2012 Minimum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jan. 31, 2010 Maximum [Member] Public Service Company of New Mexico [Member] San Juan Generating Station And Four Corners [Member] opp	Jun. 30, 2014 Maximum [Member] Mercury Control [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Oct. 31, 2012 Maximum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Clean Air Act, SCR [Member] [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Oct. 31, 2012 Maximum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Dec. 20, 2013 Maximum [Member] Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] Clean Air Act, SNCR [Member] Public Service Company of New Mexico [Member] San Juan Generating Station Units 1 and 4 [Member]	Nov. 08, 2013 San Juan Generating Station [Member] National Ambient Air Quality Standards [Member] Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss								$ 58,000,000						$ 80,300,000
Loss Contingency Accrual											12,100,000	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
Public Utilities, Proposed Seeking Shorter Compliance Period																										5 years
Public Utilities, Number of years after issuance of final determination to achieve compliance with requirements																											3 years
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
Estimated Portion of Total Capital Costs if Requirement Occured																																105,000,000				110,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share			46.30%
Net book value				286,000,000
Public Utilities, Requested Time Period to Recover Retired Units NBV																				20 years
Public Utilities, Expected NBV of Units at Retirement																				205,000,000
Public Utilities, Number of Megawatts Nuclear Generation										134														134
Public Utilities, Proposed value per Kilowatt effective January 1, 2018																								2,500
Public Utilities, Additional Ownership To Be Obtained, in Megawatts																						132	78
Public Utilities, Costs to obtain additional ownership																						0
Public Utilities, Overall Reduction Of Ownership, in Megawatts																	340
Public Utilities, Ownership To Be Exchanged, in Megawatts																			78
Jointly Owned Utility Plan, Proposed Proportionate Ownership Share					59.00%	52.00%
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
Percentage of ownership held by exiting owners																		50.00%			38.80%
Public Utilities, Ownership Percentage																13.00%		50.00%			38.50%
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 $)	Jun. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 0
Contractual Liability	2,740,000	2,398,000
Existing Cash Collateral	0	0
Net Exposure	$ 1,663,000	$ 2,152,000
Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Long Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	(2,809,507)	(3,343,783)

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Accumulated Other Comprehensive Income (Loss) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Equity [Abstract]
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process			23.00%	16.40%
Percentage of Pension Liability Adjustment Capitalized into Other Accounts			2.10%	2.50%
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			$ (58,140)	$ (81,630)
Amounts reclassified from AOCI (pre-tax)			(6,105)	(3,573)
Income tax impact of amounts reclassified			2,411	1,417
Other OCI changes (pre-tax)			9,702	8,594
Income tax impact of other OCI changes			(3,756)	(3,402)
Net change after income taxes	1,461	(1,903)	2,252	3,036
Ending Balance	(55,888)	(78,594)	(55,888)	(78,594)
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)			(8,857)	(6,854)
Income tax impact of amounts reclassified			3,488	2,714
Other OCI changes (pre-tax)			9,855	8,591
Income tax impact of other OCI changes			(3,809)	(3,401)
Net change after income taxes			677	1,050
Ending Balance	26,425	17,456	26,425	17,456
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)			2,576	3,182
Income tax impact of amounts reclassified			(1,016)	(1,262)
Other OCI changes (pre-tax)
Income tax impact of other OCI changes
Net change after income taxes			1,560	1,920
Ending Balance	(82,065)	(95,900)	(82,065)	(95,900)
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)			176	99
Income tax impact of amounts reclassified			(61)	(35)
Other OCI changes (pre-tax)			(153)	3
Income tax impact of other OCI changes			53	(1)
Net change after income taxes			15	66
Ending Balance	(248)	(150)	(248)	(150)
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)			(6,281)	(3,672)
Income tax impact of amounts reclassified			2,472	1,452
Other OCI changes (pre-tax)			9,855	8,591
Income tax impact of other OCI changes			(3,809)	(3,401)
Net change after income taxes	1,382	(1,930)	2,237	2,970
Ending Balance	(55,640)	(78,444)	(55,640)	(78,444)
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)			(8,857)	(6,854)
Income tax impact of amounts reclassified			3,488	2,714
Other OCI changes (pre-tax)			9,855	8,591
Income tax impact of other OCI changes			(3,809)	(3,401)
Net change after income taxes			677	1,050
Ending Balance	26,425	17,456	26,425	17,456
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)			2,576	3,182
Income tax impact of amounts reclassified			(1,016)	(1,262)
Other OCI changes (pre-tax)
Income tax impact of other OCI changes
Net change after income taxes			1,560	1,920
Ending Balance	(82,065)	(95,900)	(82,065)	(95,900)
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)			176	99
Income tax impact of amounts reclassified			(61)	(35)
Other OCI changes (pre-tax)			(153)	3
Income tax impact of other OCI changes			53	(1)
Net change after income taxes	79	27	15	66
Ending Balance	(248)	(150)	(248)	(150)
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)			176	99
Income tax impact of amounts reclassified			(61)	(35)
Other OCI changes (pre-tax)			(153)	3
Income tax impact of other OCI changes			53	(1)
Net change after income taxes			15	66
Ending Balance	$ (248)	$ (150)	$ (248)	$ (150)

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Regulatory and Rate Matters (Details) (USD $)											3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	0 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	1 Months Ended	3 Months Ended	0 Months Ended			3 Months Ended	6 Months Ended	12 Months Ended	1 Months Ended				0 Months Ended		1 Months Ended	3 Months Ended	6 Months Ended						6 Months Ended
	Jun. 30, 2014 Public Service Company of New Mexico [Member] La Luz Generating Station [Member] MW	Jun. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Maximum [Member]	Jun. 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]	Jun. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2011 [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2015 [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2020 [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] 2014 Wind generated Renewable Energy Credits [Member] MWh	Jun. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard 2014 [Member] MW	Jun. 30, 2014 Public Service Company of New Mexico [Member] 2015 Wind generated Renewable Energy Credits [Member] MWh	Jun. 30, 2014 Public Service Company of New Mexico [Member] Renewable Portfolio Standard 2015 [Member] MW	Oct. 05, 2012 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Disincentives / Incentives Adder [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Disincentives / Incentives Adder [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Jun. 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]	Jun. 30, 2014 Public Service Company of New Mexico [Member] Renewable Energy Rider [Member] Maximum [Member]	Jul. 31, 2011 Public Service Company of New Mexico [Member] Integrated Resource Plan, 2011 [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] Integrated Resource Plan, 2011 [Member]	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]	Jun. 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]	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]	Jul. 30, 2011 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	Jun. 30, 2014 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] customer	Jun. 30, 2014 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] Minimum [Member]	Jun. 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]	Jun. 30, 2014 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Jan. 31, 2013 Texas-New Mexico Power Company [Member] Transmission Rate Filings [Member]	Jun. 30, 2014 Texas-New Mexico Power Company [Member] August 2013 Transmission Rate Filings [Member]	Jun. 30, 2014 Texas-New Mexico Power Company [Member] January 2014 Transmission Rate Filings [Member]	Jun. 30, 2014 Texas-New Mexico Power Company [Member] July 2014 Transmission Rate Filings [Member]	Jun. 30, 2014 Delta [Member] Public Service Company of New Mexico [Member] Applications for Approvals to Purchase Delta [Member] MW	Dec. 20, 2013 San Juan Generating Station Unit 3 [Member] Public Service Company of New Mexico [Member] Clean Air Act, SNCR [Member] MW	Jun. 26, 2014 San Juan Generating Station Unit 4 [Member] Public Service Company of New Mexico [Member] Clean Air Act, SNCR [Member] MW	Dec. 20, 2013 San Juan Generating Station Unit 4 [Member] Public Service Company of New Mexico [Member] Clean Air Act, SNCR [Member] MW	Jun. 30, 2014 Four Corners [Member] Public Service Company of New Mexico [Member] Right of first refusal [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 Watts of Solar PV Capacity												23		40
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, Number of Mega Watt Hours of Wind Generation											50,000		120,000
Public Utilities, Annual Revenue To be Collected Under Current Rider Rate																				34,600,000
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, Program Costs Related To Energy Efficiency															22,500,000
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
Percentage ownership of EIP transmission line																									60.00%
Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013																				10.50%
Public Utilities, Planning Period Covered of IRP																					20 years
Amount of Regulatory Costs Not yet Approved																									3,200,000
Public Utilities, Requested Rate Increase (Decrease), Amount																							500,000	1,300,000
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
Public Utilities, Additional Ownership To Be Obtained, in Megawatts																																								78
Public Utilities, Additional Ownership To Be Obtained, in Megawatts																																									132	78
Percentage of ownership held by exiting owners																																											7.00%
Period of time to file a waiver of rights of first refusal																																											120 days
Public Utilities, Return on Equity																									10.81%
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																														0
Public Utilities, Approved Non-standard metering service cost initial fee range																															63.97	168.61
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, Approved Non-standard metering ongoing expenses monthly charge																														36.78
Presumed number of customers that will elect non-standard meter service																														1,081
Public Utilities, Non-standard metering ongoing expenses monthly charge																														38.99
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
Public Utilities, Revenue For Power Sold Under Specific Contract																										2,900,000	6,100,000	11,700,000
Public Utilities, Approved Deployment Costs																													113,300,000
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, 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

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Financing, Short-term Debt (Details) (USD $)															3 Months Ended
	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014 Line of Credit [Member]	Dec. 31, 2013 Line of Credit [Member]	Jun. 30, 2014 PNM Resources [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 PNM Resources [Member] Revolving Credit Facility [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member] Revolving Credit Facility [Member]	Jun. 30, 2014 Texas-New Mexico Power Company [Member]	Dec. 31, 2013 Texas-New Mexico Power Company [Member]	Jun. 30, 2014 Texas-New Mexico Power Company [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 Texas-New Mexico Power Company [Member] Revolving Credit Facility [Member]	Jun. 30, 2014 Texas-New Mexico Power Company [Member] Notes Payable to Banks [Member]	Jul. 25, 2014 Available Borrowing Capacity [Member]	Jul. 25, 2014 Available Borrowing Capacity [Member] PNM Resources [Member]	Jul. 25, 2014 Available Borrowing Capacity [Member] Public Service Company of New Mexico [Member]	Jul. 25, 2014 Available Borrowing Capacity [Member] Texas-New Mexico Power Company [Member]	Jul. 25, 2014 Subsequent Event [Member] PNM Resources [Member]	Jul. 25, 2014 Subsequent Event [Member] Public Service Company of New Mexico [Member]	Jul. 25, 2014 Subsequent Event [Member] Texas-New Mexico Power Company [Member]	Jul. 25, 2014 Affiliated Entity [Member] Intercompany loan agreements [Member] Public Service Company of New Mexico [Member]	Jul. 25, 2014 Affiliated Entity [Member] Intercompany loan agreements [Member] Texas-New Mexico Power Company [Member]	Jun. 30, 2014 PNMR Term Loan Agreement [Member]	Dec. 31, 2013 PNMR Term Loan Agreement [Member]	Jun. 30, 2014 First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] Texas-New Mexico Power Company [Member] Revolving Credit Facility [Member]	Jun. 30, 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]	Jul. 25, 2014 Local Lines of Credit [Member] Available Borrowing Capacity [Member] Public Service Company of New Mexico [Member]	Apr. 22, 2013 PNM Term Loan Agreement [Member] Notes Payable to Banks [Member]	Jun. 30, 2014 PNM 2014 Term Loan Agreement [Member] Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity																$ 771,800,000	$ 292,300,000	$ 369,600,000	$ 74,900,000											$ 35,000,000
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
Short-term Debt, Weighted Average Interest Rate					1.66%																				1.00%
Short-term debt	105,000,000	149,200,000	105,000,000	149,200,000	5,000,000	0	0	49,200,000	0	49,200,000			0	0											100,000,000	100,000,000		0	0		75,000,000
Short-term debt – affiliate											25,200,000	29,400,000											5,500,000	25,700,000
Restricted Cash and Investments																				1,900,000	0	0
Debt Instrument, Interest Rate at Period End																																1.10%
Proceeds from Bank Debt															$ 30,000,000

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Significant Accounting Policies and Responsibility for Financial Statements

6 Months Ended

Jun. 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 June 30, 2014 and December 31, 2013, the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2014 and 2013, and the consolidated cash flows for the six months ended June 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 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.

TNMP declared and paid cash dividends of $6.8 million and $3.7 million in the six months ended June 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

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.

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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		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			$ 43,613		$ 42,602
Available-for-sale securities, Fair value	236,427		236,427		226,855
Proceeds from sales	30,316	61,821	53,119	76,106
Gross realized gains	5,364	4,905	8,482	6,243
Gross realized (losses)	(665)	(1,688)	(1,210)	(1,496)
Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			0		0
Available-for-sale securities, Fair value	3,114		3,114		3,356
Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			16,014		14,523
Available-for-sale securities, Fair value	42,664		42,664		39,460
Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			19,931		25,656
Available-for-sale securities, Fair value	75,621		75,621		76,292
International and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			2,227		1,040
Available-for-sale securities, Fair value	17,848		17,848		16,633
U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			534		158
Available-for-sale securities, Fair value	19,814		19,814		21,941
Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			4,282		1,018
Available-for-sale securities, Fair value	65,872		65,872		58,568
Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized gains			625		207
Available-for-sale securities, Fair value	11,494		11,494		10,605
Fair Value, Measurements, Recurring [Member] | Nuclear Decommissioning Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	231,900		231,900		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

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Fair Value of Derivative and Other Financial Instruments (Tables)

6 Months Ended

Jun. 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
June 30, 2014	(In thousands)
PNMR
Long-term debt	$	1,875,254	$	2,088,787	$	—	$	2,088,787	$	—
Investment in PVNGS lessor notes	$	42,234	$	45,067	$	—	$	—	$	45,067
Other investments	$	1,798	$	2,525	$	677	$	—	$	1,848
PNM
Long-term debt	$	1,390,637	$	1,530,418	$	—	$	1,530,418	$	—
Investment in PVNGS lessor notes	$	42,234	$	45,067	$	—	$	—	$	45,067
Other investments	$	432	$	432	$	432	$	—	$	—
TNMP
Long-term debt	$	365,851	$	431,706	$	—	$	431,706	$	—
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	$	—	$	—

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
	June 30, 2014			December 31, 2013
PNMR and PNM	(In thousands)
Current assets	$	4,082		$	4,064
Deferred charges	1,515			3,002
	5,597			7,066
Current liabilities	(5,073		)	(2,699		)
Long-term liabilities	(915		)	(1,094		)
	(5,988		)	(3,793		)
Net	$	(391	)	$	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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
PNMR and PNM	(In thousands)
Electric operating revenues	$	(324	)	$	3,269		$	(4,475	)	$	(1,334	)
Cost of energy	57			(263		)	245			493
Total gain (loss)	$	(267	)	$	3,006		$	(4,230	)	$	(841	)

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
June 30, 2014
PNMR and PNM	1,165,000	(2,809,507	)
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)
June 30, 2014
PNMR and PNM	$	2,740	$	—	$	1,663
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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In thousands)
Proceeds from sales	$	30,316		$	61,821		$	53,119		$	76,106
Gross realized gains	$	5,364		$	4,905		$	8,482		$	6,243
Gross realized (losses)	$	(665	)	$	(1,688	)	$	(1,210	)	$	(1,496	)

The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table. At June 30, 2014 and December 31, 2013, the fair value of available-for-sale securities included $231.9 million and $222.5 million for the NDT and $4.5 million and $4.4 million for the mine reclamation trust.

	June 30, 2014				December 31, 2013
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,114	$	—	$	3,356
Equity securities:
Domestic value	16,014		42,664		14,523		39,460
Domestic growth	19,931		75,621		25,656		76,292
International and other	2,227		17,848		1,040		16,633
Fixed income securities:
U.S. Government	534		19,814		158		21,941
Municipals	4,282		65,872		1,018		58,568
Corporate and other	625		11,494		207		10,605
	$	43,613	$	236,427	$	42,602	$	226,855

Investments Classified by Contractual Maturity Date

At June 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	$	2,911	$	12,017	$	12,017
After 1 year through 5 years	21,556		33,776		33,050
After 5 years through 10 years	10,875		—		—
After 10 years through 15 years	9,114		—		—
After 15 years through 20 years	11,431		—		—
After 20 years	41,293		—		—
	$	97,180	$	45,793	$	45,067

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 June 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)
June 30, 2014	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,114		$	3,114	$	—
Equity securities:
Domestic value	42,664			42,664		—
Domestic growth	75,621			75,621		—
International and other	17,848			17,848		—
Fixed income securities:
U.S. Government	19,814			18,053		1,761
Municipals	65,872			—		65,872
Corporate and other	11,494			2,481		9,013
	$	236,427		$	159,781	$	76,646
Commodity derivative assets	$	5,597		$	—	$	5,597
Commodity derivative liabilities	(5,988		)	—		(5,988		)
Net	$	(391	)	$	—	$	(391	)
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 (Tables) (Public Service Company of New Mexico [Member])

6 Months Ended

Jun. 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Operating revenues	$	5,307		$	4,922		$	10,238		$	9,697
Operating expenses	(1,399		)	(1,349		)	(2,799		)	(2,920		)
Earnings attributable to non-controlling interest	$	3,908		$	3,573		$	7,439		$	6,777

Financial Position

	June 30,		December 31,
	2014		2013
	(In thousands)
Current assets	$	3,232	$	2,658
Net property, plant, and equipment	73,729		75,137
Total assets	76,961		77,795
Current liabilities	682		766
Owners’ equity – non-controlling interest	$	76,279	$	77,029

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Fair Value of Derivative and Other Financial Instruments, Debt Maturities (Details) (USD $) In Thousands, unless otherwise specified	Jun. 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	$ 2,911
Available-for-sale debt securities, After 1 year through 5 years	21,556
Available-for-sale debt securities, After 5 years through 10 years	10,875
Available-for-sale debt securities, After 10 years through 15 years	9,114
Available-for-sale debt securities, After 15 years through 20 years	11,431
Available-for-sale debt securities, After 20 years	41,293
Available-for-sale debt securities	97,180
PNM Resources [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Held-to-maturity debt securities, Due within 1 year	12,017
Held-to-maturity debt securities, After 1 year through 5 years	33,776
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	45,793
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	12,017
Held-to-maturity debt securities, After 1 year through 5 years	33,050
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	$ 45,067

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Stock-Based Compensation (Tables)

6 Months Ended

Jun. 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:

	Six Months Ended June 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 six months endedJune 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	(236,260	)	$	18.90	(292,052	)	$	16.64
Forfeited	(17,151	)	$	26.43	—		$	—
Expired	(22,784	)	$	25.91	—		$	—
Outstanding at end of period	1,067,471		$	20.80	265,417		$	22.31

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

	Six Months Ended June 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)	$	1,779	$	2,189
Restricted Stock
Weighted-average grant date fair value	$	21.27	$	20.03
Total fair value of restricted shares that vested (in thousands)	$	4,854	$	4,383

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Financing (Tables)

6 Months Ended

Jun. 30, 2014

Debt Disclosure [Abstract]

Schedule of Short-term Debt [Table Text Block]

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 June 30, 2014, the weighted average interest rate was 1.66% for borrowings under the PNMR Revolving Credit Facility and 1.00% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2014. Short-term debt outstanding consisted of:

	June 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	5,000		—
PNMR Term Loan Agreement	100,000		100,000
	$	105,000	$	149,200

At July 25, 2014, PNMR, PNM, and TNMP had $292.3 million, $369.6 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 $35.0 million of availability under the PNM New Mexico Credit Facility. Total availability at July 25, 2014, on a consolidated basis, was $771.8 million for PNMR. As of July 25, 2014, PNM had $5.5 million in borrowings from PNMR and TNMP had $25.7 million in borrowings from PNMR under their intercompany loan agreements. At July 25, 2014, PNMR, PNM and TNMP had consolidated invested cash of $1.9 million, none, and none.

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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]	Public Service Company of New Mexico [Member]	Public Service Company of New Mexico [Member] Common Stock [Member]	Public Service Company of New Mexico [Member] AOCI [Member]	Public Service Company of New Mexico [Member] Retained Earnings [Member]	Public Service Company of New Mexico [Member] Parent [Member]	Public Service Company of New Mexico [Member] Non-controlling Interest in Valencia [Member]	Texas-New Mexico Power Company [Member]	Texas-New Mexico Power Company [Member] Common Stock [Member]	Texas-New Mexico Power Company [Member] Additional Paid-in Capital [Member]	Texas-New Mexico Power Company [Member] AOCI [Member]	Texas-New Mexico Power Company [Member] Retained Earnings [Member]
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
Balance TNMP at Dec. 31, 2013	1,673,569						1,210,199						502,931	64	404,166	(263)	98,964
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from stock option exercise	4,446	4,446			4,446
Awards of common stock	(13,939)	(13,939)			(13,939)
Excess tax (shortfall) from stock-based payment arrangements	(66)	(66)			(66)
Stock based compensation expense	3,399	3,399			3,399
Valencia’s transactions with its owner	(8,189)					(8,189)	(8,189)	0	0	0	0	(8,189)
Net earnings	41,609						28,021						16,336				16,336
Net earnings before subsidiary preferred stock dividends	49,312			41,873	41,873	7,439	35,460	0	0	28,021	28,021	7,439
Subsidiary preferred stock dividends	(264)			(264)	(264)
Total other comprehensive income	2,252		2,252		2,252		2,237	0	2,237	0	2,237	0	15			15
Dividends declared on preferred stock							(264)	0	0	(264)	(264)	0
Dividends declared on common stock	(14,736)			(14,736)	(14,736)								(6,803)				(6,803)
Balance TNMP at Jun. 30, 2014	1,696,534						1,240,193						512,479	64	404,166	(248)	108,497
Balance at Jun. 30, 2014	1,772,813	1,172,209	(55,888)	580,213	1,696,534	76,279	1,316,472	1,061,776	(55,640)	234,057	1,240,193	76,279
Balance at Mar. 31, 2014
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings	29,141						20,346						9,534
Net earnings before subsidiary preferred stock dividends	33,181						24,254
Subsidiary preferred stock dividends	(132)
Total other comprehensive income	1,461						1,382						79
Balance TNMP at Jun. 30, 2014	1,696,534						1,240,193						512,479
Balance at Jun. 30, 2014	$ 1,772,813						$ 1,316,472

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Pension and Other Postretirement Benefit Plans (Tables)

6 Months Ended

Jun. 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 June 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
	Six Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	91		$	130		$	—	$	—
Interest cost	15,082			14,071			2,315			2,057			411		360
Expected return on plan assets	(19,022		)	(20,965		)	(2,819		)	(2,522		)	—		—
Amortization of net (gain) loss	6,510			7,420			1,113			2,121			105		116
Amortization of prior service cost	(483		)	38			(672		)	(672		)	—		—
Net periodic benefit cost	$	2,087		$	564		$	28		$	1,114		$	516	$	476

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 June 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
	Six Months Ended June 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	$	—		$	—		$	119		$	150		$	—	$	—
Interest cost	1,597			1,544			309			283			20		18
Expected return on plan assets	(2,263		)	(2,425		)	(267		)	(252		)	—		—
Amortization of net (gain) loss	333			524			(61		)	—			—		—
Amortization of prior service cost	—			—			16			28			—		—
Net Periodic Benefit Cost (Income)	$	(333	)	$	(357	)	$	116		$	209		$	20	$	18

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Fair Value of Derivative and Other Financial Instruments, Derivative Balance Sheet Information (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Assets, Current	$ 446,825,000	$ 401,539,000
Liabilities, Current	486,869,000	492,671,000
Current assets	4,082,000	4,064,000
Deferred charges	1,515,000	3,002,000
Commodity derivative instruments, Current liabilities	(5,073,000)	(2,699,000)
Commodity derivative instruments, Long-term liabilities	(915,000)	(1,094,000)
PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Margin Deposit Assets	2,400,000	2,800,000
Derivative, Collateral, Obligation to Return Cash	100,000	200,000
Derivative, Collateral, Right to Reclaim Cash	0
Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Assets, Current	393,099,000	348,502,000
Liabilities, Current	226,303,000	357,266,000
Current assets	4,082,000	4,064,000
Deferred charges	1,515,000	3,002,000
Commodity derivative instruments, Current liabilities	(5,073,000)	(2,699,000)
Commodity derivative instruments, Long-term liabilities	(915,000)	(1,094,000)
Commodity Contract [Member] | Fair Value Hedging [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Current assets	4,082,000	4,064,000
Deferred charges	1,515,000	3,002,000
Commodity derivative instruments, Assets	5,597,000	7,066,000
Commodity derivative instruments, Current liabilities	(5,073,000)	(2,699,000)
Commodity derivative instruments, Long-term liabilities	(915,000)	(1,094,000)
Commodity derivative instruments, Liabilities	(5,988,000)	(3,793,000)
Commodity derivative instruments, Net	(391,000)	3,273,000
Commodity Contract [Member] | Fuel and Purchased Power Adjustment Clause [Member] | Fair Value Hedging [Member] | Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Assets, Current	400,000	400,000
Liabilities, Current	600,000	100,000
Palo Verde Nuclear Generating Station [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Current assets	3,000,000	3,000,000
Deferred charges	1,500,000	3,000,000
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 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
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Assets	5,597,000	7,066,000
Commodity derivative instruments, Liabilities	(5,988,000)	(3,793,000)
Commodity derivative instruments, Net	(391,000)	3,273,000
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Assets	5,597,000	7,066,000
Commodity derivative instruments, Liabilities	(5,988,000)	(3,793,000)
Commodity derivative instruments, Net	(391,000)	3,273,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Assets	0	0
Commodity derivative instruments, Liabilities	0	0
Commodity derivative instruments, Net	$ 0	$ 0

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Income Taxes (Details) (USD $)	3 Months Ended			6 Months Ended
	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 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)	(15,893,000)		(20,334,000)	(22,313,000)	(28,303,000)
Liability for Uncertain Tax Positions, Noncurrent	14,300,000			14,300,000
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
Income Tax Expense (Benefit)	(13,106,000)		(14,943,000)	(17,189,000)	(21,532,000)
Liability for Uncertain Tax Positions, Noncurrent	11,500,000			11,500,000
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
Income Tax Expense (Benefit)	(5,590,000)		(5,055,000)	(9,640,000)	(7,345,000)
Liability for Uncertain Tax Positions, Noncurrent	0			0
Tax Years 2003 and 2005 - 2008 [Member]
Income Tax Contingency [Line Items]
Income Tax Expense (Benefit)	1,300,000
Tax Years 2003 and 2005 - 2008 [Member] | Public Service Company of New Mexico [Member]
Income Tax Contingency [Line Items]
Income Tax Expense (Benefit)	(1,100,000)
Tax Years 2003 and 2005 - 2008 [Member] | Texas-New Mexico Power Company [Member]
Income Tax Contingency [Line Items]
Income Tax Expense (Benefit)	0
Tax Years 2003 and 2005 - 2008 [Member] | PNM Resources [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

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Condensed Consolidated Statements of Earnings (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Electric Operating Revenues	$ 346,160	$ 347,599	$ 675,057	$ 665,263
Operating Expenses:
Cost of energy	109,419	105,659	222,033	210,365
Administrative and general	45,235	43,139	89,093	87,829
Energy production costs	45,846	46,831	93,134	90,404
Depreciation and amortization	42,163	41,639	84,130	82,446
Transmission and distribution costs	16,068	17,148	32,974	33,443
Taxes other than income taxes	16,133	15,316	33,644	32,205
Total operating expenses	274,864	269,732	555,008	536,692
Operating income	71,296	77,867	120,049	128,571
Other Income and Deductions:
Interest income	2,040	2,833	4,158	5,467
Gains on available-for-sale securities	4,699	3,217	7,272	4,747
Other income	3,180	2,610	4,754	4,323
Other (deductions)	(2,169)	(4,194)	(5,102)	(7,546)
Net other income and deductions	7,750	4,466	11,082	6,991
Interest Charges	29,972	30,616	59,506	61,914
Earnings before Income Taxes	49,074	51,717	71,625	73,648
Income Taxes	15,893	20,334	22,313	28,303
Net Earnings	33,181	31,383	49,312	45,345
(Earnings) Attributable to Valencia Non-controlling Interest	(3,908)	(3,573)	(7,439)	(6,777)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Net Earnings Attributable to PNMR	29,141	27,678	41,609	38,304
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)	$ 0.37	$ 0.35	$ 0.52	$ 0.48
Diluted (dollars per share)	$ 0.36	$ 0.34	$ 0.52	$ 0.48
Dividends Declared per Common Share (dollars per share)	$ 0.185	$ 0.165	$ 0.370	$ 0.330
Public Service Company of New Mexico [Member]
Electric Operating Revenues	275,704	279,690	538,441	537,583
Operating Expenses:
Cost of energy	92,642	91,855	189,268	183,514
Administrative and general	40,603	36,622	79,213	75,381
Energy production costs	45,846	46,836	93,134	90,402
Depreciation and amortization	27,023	26,051	54,105	51,884
Transmission and distribution costs	10,183	11,133	21,510	21,735
Taxes other than income taxes	9,601	8,891	20,100	19,125
Total operating expenses	225,898	221,388	457,330	442,041
Operating income	49,806	58,302	81,111	95,542
Other Income and Deductions:
Interest income	2,065	2,868	4,193	5,541
Gains on available-for-sale securities	4,699	3,217	7,272	4,747
Other income	2,443	1,614	3,555	2,930
Other (deductions)	(1,630)	(1,471)	(3,647)	(2,911)
Net other income and deductions	7,577	6,228	11,373	10,307
Interest Charges	20,023	19,890	39,835	39,847
Earnings before Income Taxes	37,360	44,640	52,649	66,002
Income Taxes	13,106	14,943	17,189	21,532
Net Earnings	24,254	29,697	35,460	44,470
(Earnings) Attributable to Valencia Non-controlling Interest	(3,908)	(3,573)	(7,439)	(6,777)
Net Earnings Attributable to PNMR	20,346	26,124	28,021	37,693
Preferred Stock Dividends Requirements	(132)	(132)	(264)	(264)
Net Earnings Attributable to PNMR	20,214	25,992	27,757	37,429
Texas-New Mexico Power Company [Member]
Electric Operating Revenues	70,456	67,909	136,616	127,680
Operating Expenses:
Cost of energy	16,777	13,804	32,765	26,851
Administrative and general	8,768	10,686	18,609	21,804
Depreciation and amortization	12,003	12,279	23,844	23,960
Transmission and distribution costs	5,885	6,016	11,464	11,708
Taxes other than income taxes	5,758	5,457	11,408	10,636
Total operating expenses	49,191	48,242	98,090	94,959
Operating income	21,265	19,667	38,526	32,721
Other Income and Deductions:
Other income	586	609	1,006	946
Other (deductions)	(72)	(123)	(304)	(252)
Net other income and deductions	514	486	702	694
Interest Charges	6,655	6,759	13,252	14,005
Earnings before Income Taxes	15,124	13,394	25,976	19,410
Income Taxes	5,590	5,055	9,640	7,345
Net Earnings Attributable to PNMR	$ 9,534	$ 8,339	$ 16,336	$ 12,065

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Fair Value of Derivative and Other Financial Instruments, Recurring (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 236,427	$ 226,855
PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	236,427	226,855
PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	159,781	158,180
PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	76,646	68,675
PNMR and PNM [Member] | Cash and equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,114	3,356
PNMR and PNM [Member] | Cash and equivalents [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,114	3,356
PNMR and PNM [Member] | Cash and equivalents [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,114	3,356
PNMR and PNM [Member] | Cash and equivalents [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | Domestic value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	42,664	39,460
PNMR and PNM [Member] | Domestic value [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	42,664	39,460
PNMR and PNM [Member] | Domestic value [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	42,664	39,460
PNMR and PNM [Member] | Domestic value [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | Domestic growth [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	75,621	76,292
PNMR and PNM [Member] | Domestic growth [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	75,621	76,292
PNMR and PNM [Member] | Domestic growth [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	75,621	76,292
PNMR and PNM [Member] | Domestic growth [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | International and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,848	16,633
PNMR and PNM [Member] | International and other [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,848	16,633
PNMR and PNM [Member] | International and other [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,848	16,633
PNMR and PNM [Member] | International and other [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | U.S. Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	19,814	21,941
PNMR and PNM [Member] | U.S. Government [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	19,814	21,941
PNMR and PNM [Member] | U.S. Government [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	18,053	20,194
PNMR and PNM [Member] | U.S. Government [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,761	1,747
PNMR and PNM [Member] | Municipals [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	65,872	58,568
PNMR and PNM [Member] | Municipals [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	65,872	58,568
PNMR and PNM [Member] | Municipals [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
PNMR and PNM [Member] | Municipals [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	65,872	58,568
PNMR and PNM [Member] | Corporate and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	11,494	10,605
PNMR and PNM [Member] | Corporate and other [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	11,494	10,605
PNMR and PNM [Member] | Corporate and other [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	2,481	2,245
PNMR and PNM [Member] | Corporate and other [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	9,013	8,360
Public Service Company of New Mexico [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,530,418	1,382,938
Investment In PVNGS lessor notes	45,067	57,279
Other investments	432	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	432	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	1,530,418	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	45,067	57,279
Other investments	0	0
PNM Resources [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,088,787	1,905,230
Investment In PVNGS lessor notes	45,067	57,279
Other investments	2,525	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	677	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	2,088,787	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	45,067	57,279
Other investments	1,848	2,506
Texas-New Mexico Power Company [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	431,706	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	431,706	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
Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	5,597	7,066
Commodity derivative instruments, Liabilities	(5,988)	(3,793)
Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Measurements, Recurring [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 Contract [Member] | PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	5,597	7,066
Commodity derivative instruments, Liabilities	(5,988)	(3,793)
Carrying Amount [Member] | Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,390,637	1,290,618
Investment In PVNGS lessor notes	42,234	52,958
Other investments	432	445
Carrying Amount [Member] | PNM Resources [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,875,254	1,745,420
Investment In PVNGS lessor notes	42,234	52,958
Other investments	1,798	1,835
Carrying Amount [Member] | Texas-New Mexico Power Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	365,851	336,036
Other investments	$ 245	$ 245

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014 Public Service Company of New Mexico [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member]	Jun. 30, 2014 Texas-New Mexico Power Company [Member]	Dec. 31, 2013 Texas-New Mexico Power Company [Member]
Current Assets:
Cash and cash equivalents	$ 12,112	$ 2,533	$ 9,356	$ 21	$ 253	$ 1
Accounts receivable	92,230	90,251	68,254	70,126	23,976	20,125
Unbilled revenues	72,690	58,806	63,069	48,992	9,621	9,814
Other receivables	40,369	53,909	39,354	52,964	1,341	1,246
Affiliate receivables			11,269	10,054
Materials, supplies, and fuel stock	60,877	67,223	58,073	64,520	2,804	2,703
Regulatory assets	45,287	24,416	40,089	19,394	5,198	5,022
Commodity derivative instruments	4,082	4,064	4,082	4,064
Income taxes receivable	6,471	7,066	6,342	4,030
Current portion of accumulated deferred income taxes	58,681	58,681	43,826	43,827	6,501	6,501
Other current assets	54,026	34,590	49,385	30,510	1,662	980
Total current assets	446,825	401,539	393,099	348,502	51,356	46,392
Other Property and Investments:
Investment in PVNGS lessor notes	17,519	32,200	17,519	32,200
Available-for-sale securities	236,427	226,855	236,427	226,855
Other investments	1,798	1,835	432	445	245	245
Non-utility property	4,284	4,353	976	976	2,240	2,240
Total other property and investments	260,028	265,243	255,354	260,476	2,485	2,485
Utility Plant:
Plant in service and plant held for future use	5,659,379	5,563,061	4,375,493	4,314,016	1,119,014	1,074,193
Less accumulated depreciation and amortization	1,860,816	1,838,832	1,426,935	1,402,531	362,640	352,105
Net plant in service and plant held for future use	3,798,563	3,724,229	2,948,558	2,911,485	756,374	722,088
Construction work in progress	146,760	132,080	114,601	107,344	27,633	16,790
Nuclear fuel, net of accumulated amortization of $44,785 and $47,347	78,216	77,602	78,216	77,602
Net utility plant	4,023,539	3,933,911	3,141,375	3,096,431	784,007	738,878
Deferred Charges and Other Assets:
Regulatory assets	499,640	523,955	365,239	384,217	134,401	139,738
Goodwill	278,297	278,297	51,632	51,632	226,665	226,665
Commodity derivative instruments	1,515	3,002	1,515	3,002
Other deferred charges	94,348	94,263	82,315	83,356	9,603	8,273
Total deferred charges and other assets	873,800	899,517	500,701	522,207	370,669	374,676
Total assets	5,604,192	5,500,210	4,290,529	4,227,616	1,208,517	1,162,431
Current Liabilities:
Short-term debt	105,000	149,200	0	49,200
Short-term debt - affiliate			0	32,500
Short-term debt – affiliate					25,200	29,400
Current installments of long-term debt	158,066	75,000	39,300	75,000
Accounts payable	88,191	109,666	63,501	84,643	14,945	12,543
Affiliate payables			23,053	20,498	3,941	3,181
Customer deposits	12,914	13,456	12,914	13,456
Accrued interest and taxes	46,564	49,600	29,207	27,665	23,052	23,778
Regulatory liabilities	473	1,081	473	1,081
Commodity derivative instruments	5,073	2,699	5,073	2,699
Dividends declared	132	14,864	132	132
Other current liabilities	70,456	77,105	52,650	50,392	3,602	8,999
Total current liabilities	486,869	492,671	226,303	357,266	70,740	77,901
Long-term Debt	1,717,188	1,670,420	1,351,337	1,215,618	365,851	336,036
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	852,846	801,408	689,190	651,239	203,289	190,197
Accumulated deferred investment tax credits	24,773	25,855	24,773	25,855
Regulatory liabilities	465,176	460,649	418,178	414,611	46,998	46,038
Asset retirement obligations	100,100	96,135	99,152	95,225	815	782
Accrued pension liability and postretirement benefit cost	72,726	80,046	69,624	76,611	3,102	3,435
Commodity derivative instruments	915	1,094	915	1,094
Other deferred credits	99,257	109,805	83,056	91,340	5,243	5,111
Total deferred credits and other liabilities	1,615,793	1,574,992	1,384,888	1,355,975	259,447	245,563
Total liabilities	3,819,850	3,738,083	2,962,528	2,928,859	696,038	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	1,172,209	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	(55,888)	(58,140)	(55,640)	(57,877)	(248)	(263)
Retained earnings	580,213	553,340	234,057	206,300	108,497	98,964
Total Company common stockholders' equity	1,696,534	1,673,569	1,240,193	1,210,199	512,479	502,931
Non-controlling interest in Valencia	76,279	77,029	76,279	77,029
Total equity	1,772,813	1,750,598	1,316,472	1,287,228
Total liabilities and stockholders' equity	$ 5,604,192	$ 5,500,210	$ 4,290,529	$ 4,227,616	$ 1,208,517	$ 1,162,431

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Earnings Per Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Earnings Per Share [Abstract]
Net Earnings Attributable to PNMR	$ 29,141		$ 27,678		$ 41,609		$ 38,304
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	110,000		194,000		146,000		202,000
Average Shares – Basic	79,764,000		79,848,000		79,800,000		79,856,000
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	464,000	[1]	607,000	[1]	508,000	[1]	661,000	[1]
Average Shares – Diluted	80,228,000		80,455,000		80,308,000		80,517,000
Net Earnings Per Share of Common Stock:
Basic (dollars per share)	$ 0.37		$ 0.35		$ 0.52		$ 0.48
Diluted (dollars per share)	$ 0.36		$ 0.34		$ 0.52		$ 0.48
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares)					297,350

[1] Excludes the effect of out-of-the-money options for 297,350 shares of common stock at June 30, 2014.

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Related Party Transactions

6 Months Ended

Jun. 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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In thousands)
Services billings:
PNMR to PNM	$	22,190	$	20,837	$	43,256	$	43,489
PNMR to TNMP	6,963		6,856		14,224		14,217
PNM to TNMP	133		133		242		241
TNMP to PNMR	—		2		—		4
Interest billings:
PNMR to TNMP	83		119		180		215
PNMR to PNM	—		—		54		1
PNM to PNMR	25		37		51		78
Income tax sharing payments:
PNMR to PNM	—		45,000		—		45,000
PNMR to TNMP	—		—		—		—

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	$ 346,160	$ 347,599	$ 675,057	$ 665,263
Cost of energy	109,419	105,659	222,033	210,365
Margin	236,741	241,940	453,024	454,898
Other operating expenses	123,282	122,434	248,845	243,881
Depreciation and amortization	42,163	41,639	84,130	82,446
Operating income	71,296	77,867	120,049	128,571
Interest income	2,040	2,833	4,158	5,467
Other income (deductions)	5,710	1,633	6,924	1,524
Net interest charges	(29,972)	(30,616)	(59,506)	(61,914)
Earnings before Income Taxes	49,074	51,717	71,625	73,648
Income taxes (benefit)	15,893	20,334	22,313	28,303
Segment earnings (loss)	33,181	31,383	49,312	45,345
Valencia non-controlling interest	(3,908)	(3,573)	(7,439)	(6,777)
Subsidiary preferred stock dividends	(132)	(132)	(264)	(264)
Segment earnings (loss) attributable to PNMR	29,141	27,678	41,609	38,304
Total Assets	5,604,192	5,403,906	5,604,192	5,403,906	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	275,704	279,690	538,441	537,583
Cost of energy	92,642	91,855	189,268	183,514
Margin	183,062	187,835	349,173	354,069
Other operating expenses	106,233	103,482	213,957	206,643
Depreciation and amortization	27,023	26,051	54,105	51,884
Operating income	49,806	58,302	81,111	95,542
Interest income	2,065	2,868	4,193	5,541
Other income (deductions)	5,512	3,360	7,180	4,766
Net interest charges	(20,023)	(19,890)	(39,835)	(39,847)
Earnings before Income Taxes	37,360	44,640	52,649	66,002
Income taxes (benefit)	13,106	14,943	17,189	21,532
Segment earnings (loss)	24,254	29,697	35,460	44,470
Valencia non-controlling interest	(3,908)	(3,573)	(7,439)	(6,777)
Subsidiary preferred stock dividends	(132)	(132)	(264)	(264)
Segment earnings (loss) attributable to PNMR	20,214	25,992	27,757	37,429
Total Assets	4,290,529	4,185,189	4,290,529	4,185,189
Goodwill	51,632	51,632	51,632	51,632
TNMP Electric [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	70,456	67,909	136,616	127,680
Cost of energy	16,777	13,804	32,765	26,851
Margin	53,679	54,105	103,851	100,829
Other operating expenses	20,411	22,159	41,481	44,148
Depreciation and amortization	12,003	12,279	23,844	23,960
Operating income	21,265	19,667	38,526	32,721
Interest income	0	0	0	0
Other income (deductions)	514	486	702	694
Net interest charges	(6,655)	(6,759)	(13,252)	(14,005)
Earnings before Income Taxes	15,124	13,394	25,976	19,410
Income taxes (benefit)	5,590	5,055	9,640	7,345
Segment earnings (loss)	9,534	8,339	16,336	12,065
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Segment earnings (loss) attributable to PNMR	9,534	8,339	16,336	12,065
Total Assets	1,208,517	1,155,928	1,208,517	1,155,928
Goodwill	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	(3,362)	(3,207)	(6,593)	(6,910)
Depreciation and amortization	3,137	3,309	6,181	6,602
Operating income	225	(102)	412	308
Interest income	(25)	(35)	(35)	(74)
Other income (deductions)	(316)	(2,213)	(958)	(3,936)
Net interest charges	(3,294)	(3,967)	(6,419)	(8,062)
Earnings before Income Taxes	(3,410)	(6,317)	(7,000)	(11,764)
Income taxes (benefit)	(2,803)	336	(4,516)	(574)
Segment earnings (loss)	(607)	(6,653)	(2,484)	(11,190)
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Segment earnings (loss) attributable to PNMR	(607)	(6,653)	(2,484)	(11,190)
Total Assets	105,146	62,789	105,146	62,789
Goodwill	$ 0	$ 0	$ 0	$ 0

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Significant Accounting Policies and Responsibility for Financial Statements (Policies)

6 Months Ended

Jun. 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 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 Declared

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.

TNMP declared and paid cash dividends of $6.8 million and $3.7 million in the six months ended June 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

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	Jun. 30, 2014	Dec. 31, 2013
Allowance for uncollectible accounts	$ 1,535	$ 1,423
Accumulated depreciation, nuclear fuel	44,785	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
Public Service Company of New Mexico [Member]
Allowance for uncollectible accounts	1,535	1,423
Accumulated depreciation, nuclear fuel	$ 44,785	$ 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
Texas-New Mexico Power Company [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

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Condensed Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Net earnings	$ 29,141	$ 27,678	$ 41,609	$ 38,304
Net Earnings	33,181	31,383	49,312	45,345
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) benefit	3,999	443	6,046	5,190
Reclassification adjustment for (gains) included in net earnings, net of income tax expense (benefit)	(3,397)	(3,333)	(5,369)	(4,140)
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	1,560	1,920
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $3, $53 and $(1)	0	(6)	(100)	2
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(42), $(18), $(61) and $(35)	79	33	115	64
Net change after income taxes	1,461	(1,903)	2,252	3,036
Comprehensive Income	34,642	29,480	51,564	48,381
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,908)	(3,573)	(7,439)	(6,777)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Comprehensive Income Attributable to PNMR	30,602	25,775	43,861	41,340
Public Service Company of New Mexico [Member]
Net earnings	20,346	26,124	28,021	37,693
Net Earnings	24,254	29,697	35,460	44,470
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) benefit	3,999	443	6,046	5,190
Reclassification adjustment for (gains) included in net earnings, net of income tax expense (benefit)	(3,397)	(3,333)	(5,369)	(4,140)
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	1,560	1,920
Fair Value Adjustment for Cash Flow Hedges:
Net change after income taxes	1,382	(1,930)	2,237	2,970
Comprehensive Income	25,636	27,767	37,697	47,440
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,908)	(3,573)	(7,439)	(6,777)
Comprehensive Income Attributable to PNMR	21,728	24,194	30,258	40,663
Texas-New Mexico Power Company [Member]
Net earnings	9,534	8,339	16,336	12,065
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $3, $53 and $(1)	0	(6)	(100)	2
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(42), $(18), $(61) and $(35)	79	33	115	64
Net change after income taxes	79	27	15	66
Comprehensive Income Attributable to PNMR	$ 9,613	$ 8,366	$ 16,351	$ 12,131

XML

Financing

6 Months Ended

Jun. 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 June 30, 2014, must be repaid on or before September 4, 2015, and is reflected as 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 June 30, 2014, the weighted average interest rate was 1.66% for borrowings under the PNMR Revolving Credit Facility and 1.00% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2014. Short-term debt outstanding consisted of:

	June 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	5,000		—
PNMR Term Loan Agreement	100,000		100,000
	$	105,000	$	149,200

At July 25, 2014, PNMR, PNM, and TNMP had $292.3 million, $369.6 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 $35.0 million of availability under the PNM New Mexico Credit Facility. Total availability at July 25, 2014, on a consolidated basis, was $771.8 million for PNMR. As of July 25, 2014, PNM had $5.5 million in borrowings from PNMR and TNMP had $25.7 million in borrowings from PNMR under their intercompany loan agreements. At July 25, 2014, PNMR, PNM and TNMP had consolidated invested cash of $1.9 million, none, and none.

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Jul. 25, 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	Jun. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
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

6 Months Ended

Jun. 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 (“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 has proposed a change in mortality assumptions to reflect increased life expectancy and the corresponding decrease in mortality rates.  If adopted, 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, beginning in 2016, the Company’s pension liabilities could increase by as much as 7% over those using the current mortality assumptions.  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 June 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
	Six Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	91		$	130		$	—	$	—
Interest cost	15,082			14,071			2,315			2,057			411		360
Expected return on plan assets	(19,022		)	(20,965		)	(2,819		)	(2,522		)	—		—
Amortization of net (gain) loss	6,510			7,420			1,113			2,121			105		116
Amortization of prior service cost	(483		)	38			(672		)	(672		)	—		—
Net periodic benefit cost	$	2,087		$	564		$	28		$	1,114		$	516	$	476

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 six months ended June 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 $61.5 million. These anticipated contributions were developed using current funding assumptions, with discount rates of 5.2% to 5.5%. 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 $1.6 million in the three and six months ended June 30, 2014 and $1.1 million and $1.6 million in the three and six months ended June 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 $0.7 million in the three and six months ended June 30, 2014 and $0.4 million and $0.8 million in the three and six months ended June 30, 2013 and are expected to total $1.5 million during 2014.

TNMP Plans

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

	Three Months Ended June 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
	Six Months Ended June 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	$	—		$	—		$	119		$	150		$	—	$	—
Interest cost	1,597			1,544			309			283			20		18
Expected return on plan assets	(2,263		)	(2,425		)	(267		)	(252		)	—		—
Amortization of net (gain) loss	333			524			(61		)	—			—		—
Amortization of prior service cost	—			—			16			28			—		—
Net Periodic Benefit Cost (Income)	$	(333	)	$	(357	)	$	116		$	209		$	20	$	18

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 six months ended June 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 5.2% and 5.5%. 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 $0.3 million in the three and six months ended June 30, 2014 and $0.3 million in the three and six months ended June 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 six months ended June 30, 2014 and 2013 and are expected to total $0.1 million during 2014.

XML

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Unrealized holding gains (losses) arising during the period, income tax (expense)	$ (2,602)	$ (290)	$ (3,809)	$ (3,401)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	2,210	2,185	3,488	2,714
Pension liability adjustment, income tax (expense) benefit	(508)	(631)	(1,016)	(1,262)
Change in fair market value, income tax (expense)	0	3	53	(1)
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	(42)	(18)	(61)	(35)
Public Service Company of New Mexico [Member]
Unrealized holding gains (losses) arising during the period, income tax (expense)	(2,602)	(290)	(3,809)	(3,401)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	2,210	2,185	3,488	2,714
Pension liability adjustment, income tax (expense) benefit	(508)	(631)	(1,016)	(1,262)
Texas-New Mexico Power Company [Member]
Change in fair market value, income tax (expense)	0	3	53	(1)
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	$ (42)	$ (18)	$ (61)	$ (35)

XML

Accumulated Other Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2014

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the six months ended June 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)	(8,857		)	2,576			176			(6,105		)
Income tax impact of amounts reclassified	3,488			(1,016		)	(61		)	2,411
Other OCI changes (pre-tax)	9,855			—			(153		)	9,702
Income tax impact of other OCI changes	(3,809		)	—			53			(3,756		)
Net change after income taxes	677			1,560			15			2,252
Balance at June 30, 2014	$	26,425		$	(82,065	)	$	(248	)	$	(55,888	)

PNM
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	—	$	(57,877	)
Amounts reclassified from AOCI (pre-tax)	(8,857		)	2,576			—		(6,281		)
Income tax impact of amounts reclassified	3,488			(1,016		)	—		2,472
Other OCI changes (pre-tax)	9,855			—			—		9,855
Income tax impact of other OCI changes	(3,809		)	—			—		(3,809		)
Net change after income taxes	677			1,560			—		2,237
Balance at June 30, 2014	$	26,425		$	(82,065	)	$	—	$	(55,640	)

TNMP
Balance at December 31, 2013	$	—	$	—	$	(263	)	$	(263	)
Amounts reclassified from AOCI (pre-tax)	—		—		176			176
Income tax impact of amounts reclassified	—		—		(61		)	(61		)
Other OCI changes (pre-tax)	—		—		(153		)	(153		)
Income tax impact of other OCI changes	—		—		53			53
Net change after income taxes	—		—		15			15
Balance at June 30, 2014	$	—	$	—	$	(248	)	$	(248	)

	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)	(6,854		)	3,182			99			(3,573		)
Income tax impact of amounts reclassified	2,714			(1,262		)	(35		)	1,417
Other OCI changes (pre-tax)	8,591			—			3			8,594
Income tax impact of other OCI changes	(3,401		)	—			(1		)	(3,402		)
Net change after income taxes	1,050			1,920			66			3,036
Balance at June 30, 2013	$	17,456		$	(95,900	)	$	(150	)	$	(78,594	)

PNM
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	—	$	(81,414	)
Amounts reclassified from AOCI (pre-tax)	(6,854		)	3,182			—		(3,672		)
Income tax impact of amounts reclassified	2,714			(1,262		)	—		1,452
Other OCI changes (pre-tax)	8,591			—			—		8,591
Income tax impact of other OCI changes	(3,401		)	—			—		(3,401		)
Net change after income taxes	1,050			1,920			—		2,970
Balance at June 30, 2013	$	17,456		$	(95,900	)	$	—	$	(78,444	)

TNMP
Balance at December 31, 2012	$	—	$	—	$	(216	)	$	(216	)
Amounts reclassified from AOCI (pre-tax)	—		—		99			99
Income tax impact of amounts reclassified	—		—		(35		)	(35		)
Other OCI changes (pre-tax)	—		—		3			3
Income tax impact of other OCI changes	—		—		(1		)	(1		)
Net change after income taxes	—		—		66			66
Balance at June 30, 2013	$	—	$	—	$	(150	)	$	(150	)

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 six months ended June 30, 2014 and 2013, approximately 23.0% and 16.4% of the amount reclassified was capitalized into construction work in process and approximately 2.1% and 2.5% 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

6 Months Ended

Jun. 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 June 30, 2014
Electric operating revenues	$	275,704		$	70,456		$	—		$	346,160
Cost of energy	92,642			16,777			—			109,419
Margin	183,062			53,679			—			236,741
Other operating expenses	106,233			20,411			(3,362		)	123,282
Depreciation and amortization	27,023			12,003			3,137			42,163
Operating income	49,806			21,265			225			71,296
Interest income	2,065			—			(25		)	2,040
Other income (deductions)	5,512			514			(316		)	5,710
Net interest charges	(20,023		)	(6,655		)	(3,294		)	(29,972		)
Segment earnings (loss) before income taxes	37,360			15,124			(3,410		)	49,074
Income taxes (benefit)	13,106			5,590			(2,803		)	15,893
Segment earnings (loss)	24,254			9,534			(607		)	33,181
Valencia non-controlling interest	(3,908		)	—			—			(3,908		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	20,214		$	9,534		$	(607	)	$	29,141
Six Months Ended June 30, 2014
Electric operating revenues	$	538,441		$	136,616		$	—		$	675,057
Cost of energy	189,268			32,765			—			222,033
Margin	349,173			103,851			—			453,024
Other operating expenses	213,957			41,481			(6,593		)	248,845
Depreciation and amortization	54,105			23,844			6,181			84,130
Operating income	81,111			38,526			412			120,049
Interest income	4,193			—			(35		)	4,158
Other income (deductions)	7,180			702			(958		)	6,924
Net interest charges	(39,835		)	(13,252		)	(6,419		)	(59,506		)
Segment earnings (loss) before income taxes	52,649			25,976			(7,000		)	71,625
Income taxes (benefit)	17,189			9,640			(4,516		)	22,313
Segment earnings (loss)	35,460			16,336			(2,484		)	49,312
Valencia non-controlling interest	(7,439		)	—			—			(7,439		)
Subsidiary preferred stock dividends	(264		)	—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	27,757		$	16,336		$	(2,484	)	$	41,609
At June 30, 2014:
Total Assets	$	4,290,529		$	1,208,517		$	105,146		$	5,604,192
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended June 30, 2013
Electric operating revenues	$	279,690		$	67,909		$	—		$	347,599
Cost of energy	91,855			13,804			—			105,659
Margin	187,835			54,105			—			241,940
Other operating expenses	103,482			22,159			(3,207		)	122,434
Depreciation and amortization	26,051			12,279			3,309			41,639
Operating income (loss)	58,302			19,667			(102		)	77,867
Interest income	2,868			—			(35		)	2,833
Other income (deductions)	3,360			486			(2,213		)	1,633
Net interest charges	(19,890		)	(6,759		)	(3,967		)	(30,616		)
Segment earnings (loss) before income taxes	44,640			13,394			(6,317		)	51,717
Income taxes (benefit)	14,943			5,055			336			20,334
Segment earnings (loss)	29,697			8,339			(6,653		)	31,383
Valencia non-controlling interest	(3,573		)	—			—			(3,573		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	25,992		$	8,339		$	(6,653	)	$	27,678
Six Months Ended June 30, 2013
Electric operating revenues	$	537,583		$	127,680		$	—		$	665,263
Cost of energy	183,514			26,851			—			210,365
Margin	354,069			100,829			—			454,898
Other operating expenses	206,643			44,148			(6,910		)	243,881
Depreciation and amortization	51,884			23,960			6,602			82,446
Operating income	95,542			32,721			308			128,571
Interest income	5,541			—			(74		)	5,467
Other income (deductions)	4,766			694			(3,936		)	1,524
Net interest charges	(39,847		)	(14,005		)	(8,062		)	(61,914		)
Segment earnings (loss) before income taxes	66,002			19,410			(11,764		)	73,648
Income taxes (benefit)	21,532			7,345			(574		)	28,303
Segment earnings (loss)	44,470			12,065			(11,190		)	45,345
Valencia non-controlling interest	(6,777		)	—			—			(6,777		)
Subsidiary preferred stock dividends	(264		)	—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	37,429		$	12,065		$	(11,190	)	$	38,304
At June 30, 2013:
Total Assets	$	4,185,189		$	1,155,928		$	62,789		$	5,403,906
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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Goodwill

6 Months Ended

Jun. 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 June 6, 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM.

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

6 Months Ended

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

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 June 30, 2014 and December 31, 2013, PNM had a liability for interim storage costs of $12.1 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. NRC Commissioners have instructed the staff to issue the final generic EIS and rule by no later than September 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. The fee applicable to PVNGS Units 1 and 2 is recovered by PNM in its retail rates. 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. In 2013, the one-mill fee for PNM’s share of the output from all three units at PVNGS amounted to $3.0 million. 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. 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 requires installation of selective catalytic reduction technology (“SCR”) with stringent NOx emission limits on all four units by September 21, 2016.

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 on March 1, 2012. These parties also formally asked EPA to stay the effective date of the rule. Several environmental groups have intervened in support of EPA. WEG also filed an action to challenge EPA’s rule in the Tenth Circuit, seeking to shorten the rule’s compliance period from five years to three years and PNM has intervened in this action. Oral arguments on the merits of the FIP challenges were held in October 2012 in the Tenth Circuit. In accordance with the court’s order, the parties have filed supplemental information.

In litigation involving several environmental groups, the United States District Court for the District of Columbia entered a consent decree, which, as amended, required EPA to issue a final rulemaking on New Mexico’s regional haze SIP by November 15, 2012. EPA approved all components of the SIP, except for the NOx BART determination for SJGS. With respect to that element of the SIP, EPA determined that with the FIP in place, it had met its obligation under the consent decree.

Because the unchanged compliance deadline of the FIP required PNM to continue to take steps to commence installation of SCRs at SJGS, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, has been suspended through November 1, 2014. 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, which amounts include costs for construction management, gross receipts taxes, AFUDC, and other PNM costs, although final costs were to be refined through an “open book” subcontractor bidding process. 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 estimates for SNCRs and the NAAQS requirements 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%.

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, subject to approval by the EIB and EPA. 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. Certain aspects of this alternative are subject to approval by the NMPRC. At June 30, 2014, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $286 million.

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.

This revised plan primarily focuses on how SJGS would meet the regional haze rule and also indicates that PNM would build a natural gas-fired generating plant in the “four corners” region to partially replace the capacity from the retired coal units. Detailed replacement power strategies also would be finalized.  PNM believes adequate replacement power alternatives will be available to meet its generation needs and ensure reliability.

It was contemplated that the retirement of SJGS Units 2 and 3 under the revised plan might result in shifts in ownership among SJGS owners or other changes in the contractual cost sharing arrangements, as would be agreed upon by the owners. See SJGS Ownership Restructuring Matters below. Owners of the affected units also may be required to seek approvals of their utility commissions or governing boards for any such changes.

The parties file periodic status reports with the Tenth Circuit.  To demonstrate that progress has been made toward settling the Tenth Circuit litigation, information, including the non-binding agreement and its accompanying timeline, was submitted to the Tenth Circuit. Following the parties’ submission of their status reports, on February 28, 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals. On October 17, 2013, the court ruled on a motion filed by PNM for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously filed motion to stay the EPA rule. The court placed the pending petitions for review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the agreement in principle fails or is not implemented as was indicated in the term sheet and timeline, any party to the litigation may file a motion seeking to lift the abatement.  PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

Due to the long lead times on certain equipment purchases, PNM began taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In April 2013, PNM issued an RFP for SNCR system design and technology. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider and in July 2014 entered into a contract for management of the SNCR construction, but has not yet entered into a construction and procurement contract.

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, including the installation of SNCRs on Units 1 and 4 and the retirement of Units 2 and 3. NMED developed a revised SIP and submitted it to the EIB for approval in May 2013. After a public hearing, the EIB approved the revised SIP in September 2013 and the revised SIP was submitted to EPA for approval on October 18, 2013. EPA deemed the SIP application complete on December 17, 2013. On April 30, 2014, EPA issued an advance copy of its proposed approval of the revised SIP and it was published in the Federal Register on May 12, 2014. EPA provided a 30 day public comment period, which ended on June 11, 2014. PNM filed comments in support of EPA’s proposed approval. Final EPA action on the revised SIP is expected by about the end of September 2014.

On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the revised SIP. 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, estimated to be approximately $205 million, 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

In its filing, PNM requested the NMPRC to issue its final ruling on the application no later than December 2014. On February 11, 2014, the Hearing Examiner issued an order finding that PNM’s application is complete. The order also stated that there was not a statutory time clock for the request to retire SJGS Units 2 and 3 and the statutory time clock on the CCN requests has not yet begun. The Hearing Examiner found that the NMPRC should proceed with the review of PNM’s application and establish a schedule that would allow NMPRC action on the application by the end of 2014.

The above estimate of PNM’s share of the costs to install SNCRs and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 includes gross receipts taxes, AFUDC, and other PNM costs. This amount and the above estimate of net book value of SJGS Units 2 and 3 at December 31, 2017 reflect the requested exchange of 78 MW of capacity out of SJGS Unit 3 and into SJGS Unit 4 resulting in PNM’s ownership share of SJGS Units 1 and 4 aggregating approximately 52%. The December 20, 2013 NMPRC filing identifies 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. See Note 12. Specific approvals to acquire other facilities 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 will 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 either SCRs or 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 revised SIP. 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. PNM’s ultimate ownership percentage in SJGS Unit 4 will depend on the final resolution of the negotiations among the SJGS owners and is subject to NMPRC approval. On July 1, 2014, pursuant to an order of the hearing examiner in the case, 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, which are memorialized in the resolution and term sheet described below. PNM filed testimony with the NMPRC on July 15, 2014 further describing the proposed terms. The public hearing in the NMPRC case is now scheduled to begin on October 6, 2014. PNM is currently requesting that the NMPRC take action on this case by the end of February 2015.

PNM can provide no assurance that the requirements of the plan agreed to on February 15, 2013 will be accomplished within the required timeframes or at all. If the February 15, 2013 plan is not implemented, PNM would seek to work with NMED and EPA to develop a revised timetable for implementation of the FIP. If an agreement on a revised timetable cannot be reached, PNM will likely be unable to complete the installation of SCRs on all four units at SJGS by the FIP deadline of September 21, 2016. In such event, PNM would need to rely on EPA’s pledge to work with PNM and the State of New Mexico to develop a reasonable FIP compliance plan or otherwise negotiate a solution with EPA or seek relief from the Tenth Circuit in order to continue to be able to operate the plant, including during the installation process for any alternate solution. If relief is not granted, PNM could be forced to temporarily cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire temporary replacement power through short-term or open-market purchases in order to serve the needs of its customers. There can be no assurance that sufficient replacement power will be available to serve PNM’s needs or, if available, what costs would be incurred.

PNM is unable to predict the ultimate outcome of these matters or what additional pollution control equipment will be required at SJGS.PNM will seek recovery from its ratepayers for all costs that may be incurred as a result of the CAA requirements. 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.

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. PNM is unable to predict the actions of the SJGS participants. Likewise, PNM cannot predict the impact of those actions on the ownership of SJGS or the operations of SJGS and PNM.

The SJGS participants have engaged in negotiations concerning the implementation of the revised SIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 in order to facilitate the shutdown of Units 2 and 3 to comply with the revised SIP and to accommodate the intent of the participants desiring to exit ownership in SJGS. This could have resulted in certain of the continuing participants, including PNM, acquiring additional ownership interests in Unit 4 prior to the shutdown of SJGS Units 2 and 3. Based on the status of negotiations at the time of PNM’s December 20, 2013 NMPRC filing, PNM requested NMPRC approval to exchange 78 MW of its capacity in SJGS Unit 3 for an equal amount of capacity in SJGS Unit 4. 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. The SJGS participants engaged a mediator to assist in facilitating resolution of a number of outstanding matters among the owners.

On June 26, 2014, a non-binding resolution was unanimously approved by the SJGS Coordination Committee. 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 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. The non-binding 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. The participants continue to negotiate definitive agreements that would formalize these matters, as well as addressing plant decommissioning liabilities and indemnification. 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 proposes to acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017, rather than the exchange of 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 contemplated in the December 20, 2013 NMPRC filing. 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 Units 1 and 4 aggregating approximately 59%. PNM’s remaining replacement power plans otherwise remain as previously proposed.

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.

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, 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. The SJPPA provides that PNM, in its capacity as operating agent of SJGS, is authorized and obligated 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. On March 11, 2014, PNM requested that the owners of Unit 4 approve the expenditure of $1.9 million of costs critical to being able to comply with the time frame in the revised SIP with respect to the Unit 4 project. The Unit 4 owners did not approve the expenditures. Thereafter, PNM, as operating agent for SJGS, issued a “Prudent Utility Practice” notice under the SJPPA indicating PNM was restarting certain critical activities to keep the Unit 4 SNCR project on schedule. On June 27, 2014, PNM requested that the Unit 4 owners approve the expenditure of an additional $6.4 million of costs critical to the next phase of the Unit 4 capital project and compliance with the revised SIP deadline. The Unit 4 owners did not approve the additional expenditures. PNM subsequently issued a notice to the participants on July 14, 2014, that, consistent with “Prudent Utility Practice,” PNM must continue the work on Unit 4 and would begin to incur the additional expenditures. PNM cannot predict the outcome of this matter, its impact on SJGS’ compliance with the CAA, or the impact on PNM’s financial position, results of operations, and cash flows.

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.  The deadline for comments on the draft EIS, which originally were due by the May 27, 2014, was extended to June 27, 2014.  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. PNM is unable to predict whether WEG will file a petition for rehearing or otherwise appeal the decision.

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. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

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 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 stated it intends to propose a new standard. Although EPA has not announced a timeline for its review, it may release new proposed standards in the second half of 2014.  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 seek 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. In accordance with the stipulated order, PNM will repeat the mercury study required under the Consent Decree using sorbent traps instead of the monitoring system used in the initial study. 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 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 voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines, 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. 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 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 voluntarily agreed to conduct similar sampling activities on the site beginning in April 2014, as well as more specific “fingerprint” analysis, which may help identify potential off-site sources. PNM is unable to predict the outcome of this matter and does not believe the former generating station is the source of the nitrates or the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made.

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. 

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 June 30, 2014 and December 31, 2013, prepayments for coal, which are included in other current assets, amounted to $21.6 million and $12.3 million. These amounts reflect delivery of a portion of the prepaid coal and its utilization due to the mine fire incident described below. 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.

APS purchases 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 $54.6 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 June 30, 2014 and December 31, 2013, liabilities, in current dollars, of $23.3 million and $23.8 million for surface mine reclamation and $8.2 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. It has not been decided how costs would be divided among the owners of SJGS. 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 has 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.

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, Delta, 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.  If the challenge to the ordinance is 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

6 Months Ended

Jun. 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 six months ended June 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
	June 30, 2014			December 31, 2013
PNMR and PNM	(In thousands)
Current assets	$	4,082		$	4,064
Deferred charges	1,515			3,002
	5,597			7,066
Current liabilities	(5,073		)	(2,699		)
Long-term liabilities	(915		)	(1,094		)
	(5,988		)	(3,793		)
Net	$	(391	)	$	3,273

Included in the above table are $3.0 million of current assets and $1.5 million of deferred charges at June 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 June 30, 2014 and December 31, 2013.

At June 30, 2014 and December 31, 2013, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at June 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 $0.1 million at June 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 $0.4 million of current assets and $0.6 million of current liabilities at June 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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
PNMR and PNM	(In thousands)
Electric operating revenues	$	(324	)	$	3,269		$	(4,475	)	$	(1,334	)
Cost of energy	57			(263		)	245			493
Total gain (loss)	$	(267	)	$	3,006		$	(4,230	)	$	(841	)

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
June 30, 2014
PNMR and PNM	1,165,000	(2,809,507	)
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)
June 30, 2014
PNMR and PNM	$	2,740	$	—	$	1,663
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 June 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 June 30, 2014 and December 31, 2013, the fair value of available-for-sale securities included $231.9 million and $222.5 million for the NDT and $4.5 million and $4.4 million for the mine reclamation trust.

	June 30, 2014				December 31, 2013
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,114	$	—	$	3,356
Equity securities:
Domestic value	16,014		42,664		14,523		39,460
Domestic growth	19,931		75,621		25,656		76,292
International and other	2,227		17,848		1,040		16,633
Fixed income securities:
U.S. Government	534		19,814		158		21,941
Municipals	4,282		65,872		1,018		58,568
Corporate and other	625		11,494		207		10,605
	$	43,613	$	236,427	$	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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In thousands)
Proceeds from sales	$	30,316		$	61,821		$	53,119		$	76,106
Gross realized gains	$	5,364		$	4,905		$	8,482		$	6,243
Gross realized (losses)	$	(665	)	$	(1,688	)	$	(1,210	)	$	(1,496	)

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 June 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	$	2,911	$	12,017	$	12,017
After 1 year through 5 years	21,556		33,776		33,050
After 5 years through 10 years	10,875		—		—
After 10 years through 15 years	9,114		—		—
After 15 years through 20 years	11,431		—		—
After 20 years	41,293		—		—
	$	97,180	$	45,793	$	45,067

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 June 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)
June 30, 2014	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,114		$	3,114	$	—
Equity securities:
Domestic value	42,664			42,664		—
Domestic growth	75,621			75,621		—
International and other	17,848			17,848		—
Fixed income securities:
U.S. Government	19,814			18,053		1,761
Municipals	65,872			—		65,872
Corporate and other	11,494			2,481		9,013
	$	236,427		$	159,781	$	76,646
Commodity derivative assets	$	5,597		$	—	$	5,597
Commodity derivative liabilities	(5,988		)	—		(5,988		)
Net	$	(391	)	$	—	$	(391	)
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 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 six months ended June 30, 2014 and the year ended December 31, 2013.

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
June 30, 2014	(In thousands)
PNMR
Long-term debt	$	1,875,254	$	2,088,787	$	—	$	2,088,787	$	—
Investment in PVNGS lessor notes	$	42,234	$	45,067	$	—	$	—	$	45,067
Other investments	$	1,798	$	2,525	$	677	$	—	$	1,848
PNM
Long-term debt	$	1,390,637	$	1,530,418	$	—	$	1,530,418	$	—
Investment in PVNGS lessor notes	$	42,234	$	45,067	$	—	$	—	$	45,067
Other investments	$	432	$	432	$	432	$	—	$	—
TNMP
Long-term debt	$	365,851	$	431,706	$	—	$	431,706	$	—
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	$	—	$	—

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Variable Interest Entities

6 Months Ended

Jun. 30, 2014

Variable Interest Entities [Abstract]

Variable Interest Entities

Variable Interest Entities

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 six months ended June 30, 2014, PNM paid $4.8 million and $9.6 million for fixed charges and $0.5 million and $0.7 million for variable charges. For the three and six months ended June 30, 2013, PNM paid $4.7 million and $9.4 million for fixed charges and $0.2 million and $0.3 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM has 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Operating revenues	$	5,307		$	4,922		$	10,238		$	9,697
Operating expenses	(1,399		)	(1,349		)	(2,799		)	(2,920		)
Earnings attributable to non-controlling interest	$	3,908		$	3,573		$	7,439		$	6,777

Financial Position

	June 30,		December 31,
	2014		2013
	(In thousands)
Current assets	$	3,232	$	2,658
Net property, plant, and equipment	73,729		75,137
Total assets	76,961		77,795
Current liabilities	682		766
Owners’ equity – non-controlling interest	$	76,279	$	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; 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, which, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, aggregate $36.5 million as of June 30, 2014 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 June 30, 2014, PNM could have been required to pay the beneficial owners up to $144.7 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 $26.0 million at June 30, 2014 and December 31, 2013, that are included in other current liabilities on the Condensed Consolidated Balance Sheets.

Delta

PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which is 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 owns Delta. PNM made fixed and variable payments to Delta under the PPA. For the three and six months ended June 30, 2014, PNM incurred fixed capacity charges of $1.6 million and $3.2 million and variable energy charges of $0.3 million and $0.5 million under the PPA. For the three and six months ended June 30, 2013, PNM incurred fixed capacity charges of $1.6 million and $3.2 million and variable energy charges of $0.4 million and $0.6 million. PNM’s only quantifiable obligation under the PPA was to make the fixed payments, which as of June 30, 2014 aggregated $36.2 million through the end of the PPA. PNM would also pay variable costs, which could not be quantified since the amounts were based on how much the generating plant operated.

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 owns Delta, or to consolidate that entity if it were determined that PNM is 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 owns 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 estimated 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 June 30, 2014 and at closing.

Delta informed PNM that at June 30, 2014 and December 31, 2013, it had total assets of $22.4 million and $23.7 million, including net property, plant, and equipment of $19.0 million and $20.3 million, and total liabilities of $16.5 million and $18.2 million. Delta also indicated its revenue for the three and six months ended June 30, 2014 was $2.5 million and $4.3 million and its net earnings were $0.3 million and $0.6 million. Revenue for the three and six months ended June 30, 2013 was $2.2 million and $4.0 million and net earnings were $0.1 million and $0.3 million. Consolidation of Delta would be immaterial to the Condensed Consolidated Balance Sheets of PNMR and PNM. Since all of Delta’s revenues and expenses are 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 be 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

6 Months Ended

Jun. 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 31.2494 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

6 Months Ended

Jun. 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 June 30, 2014 and December 31, 2013, PNMR had unrecognized expense related to stock awards of $7.7 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:

	Six Months Ended June 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 six months endedJune 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	(236,260	)	$	18.90	(292,052	)	$	16.64
Forfeited	(17,151	)	$	26.43	—		$	—
Expired	(22,784	)	$	25.91	—		$	—
Outstanding at end of period	1,067,471		$	20.80	265,417		$	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 June 30, 2014, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $9.4 million with a weighted-average remaining contract life of 3.20 years. At June 30, 2014, the exercise price of 297,350 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:

	Six Months Ended June 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)	$	1,779	$	2,189
Restricted Stock
Weighted-average grant date fair value	$	21.27	$	20.03
Total fair value of restricted shares that vested (in thousands)	$	4,854	$	4,383

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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	1 Months Ended	3 Months Ended		6 Months Ended				1 Months Ended
	Jul. 31, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014 Texas-New Mexico Power Company [Member]	Jun. 30, 2013 Texas-New Mexico Power Company [Member]	Jul. 31, 2014 Subsequent Event [Member]
Dividends on Common Stock [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.165	$ 0.185	$ 0.165	$ 0.370	$ 0.330			$ 0.185
Dividends, Common Stock, Cash				$ 14,736		$ 6,803	$ 3,700

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Commitments and Contingencies (Other Commitments and Contingencies) (Details) (USD $)								6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014 Public Service Company of New Mexico [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member]	Jun. 30, 2014 Coal Supply [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Dec. 31, 2013 Coal Supply [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jun. 30, 2014 Surface [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Surface [Member] Loss on Long-term Purchase Commitment [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2013 Surface [Member] Loss on Long-term Purchase Commitment [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Surface [Member] Loss on Long-term Purchase Commitment [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jun. 30, 2014 Underground [Member] Loss on Long-term Purchase Commitment [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2013 Underground [Member] Loss on Long-term Purchase Commitment [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Underground [Member] Loss on Long-term Purchase Commitment [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jun. 30, 2014 San Juan Underground Mine Fire [Member] Fuel and Purchased Power Adjustment Clause [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jun. 30, 2014 San Juan Underground Mine Fire [Member] Fuel and Purchased Power Adjustment Clause [Member] Minimum [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jun. 30, 2014 San Juan Underground Mine Fire [Member] Fuel and Purchased Power Adjustment Clause [Member] Maximum [Member] Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jun. 30, 2014 NMTRD Coal Severance Tax [Member] Four Corners [Member]	Jun. 30, 2014 NMTRD Coal Severance Tax [Member] Public Service Company of New Mexico [Member] Four Corners [Member]	Apr. 02, 2014 Navajo Nation Allottee Matters [Member] Public Service Company of New Mexico [Member] Allotment_Parcel	Jan. 06, 2014 Navajo Nation Allottee Matters [Member] Public Service Company of New Mexico [Member] Allotment_Parcel	Sep. 01, 2012 Navajo Nation Allottee Matters [Member] Public Service Company of New Mexico [Member] Allotment_Parcel	Jun. 30, 2014 San Juan Generating Station [Member] Continuous Highwall Mining [Member]	Jun. 30, 2014 San Juan Generating Station [Member] SJCC Arbitration [Member]	Jun. 30, 2014 San Juan Generating Station [Member] SJCC Arbitration [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Nuclear Plant [Member] Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]	Jun. 30, 2014 Nuclear Plant [Member] Maximum [Member] Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]	Apr. 01, 2014 Nuclear Plant [Member] Maximum [Member] Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]	Jun. 30, 2014 Commercial Providers [Member] Nuclear Plant [Member] Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]	Jun. 30, 2014 Industry Wide Retrospective Assessment Program [Member] Nuclear Plant [Member] Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Other Assets, Current	$ 54,026,000	$ 34,590,000	$ 49,385,000	$ 30,510,000	$ 21,600,000	$ 12,300,000
Public Utilities, Estimated Increase in Coal Cost, Percentage					21.00%
Loss Contingency, Estimate of Possible Loss										54,600,000			93,300,000
Loss Contingency Accrual								23,300,000	23,800,000		8,200,000	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																							5,200,000.0
Public Utilities, Potential Overbilled Mining Costs SJCC Owes to SJGS Owners																							1,100,000.0
Public Utilities, Potential Capital Improvements billed as Mining Costs to SJGS Owners																							13,900,000.0
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																										13,600,000,000		375,000,000	13,200,000,000
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

6 Months Ended

Jun. 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 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. As discussed above, these liabilities are presented as reductions of deferred tax assets for net operating loss carryforwards in the Condensed Consolidated Balance Sheets at June 30, 2014.

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Segment Information (Tables)

6 Months Ended

Jun. 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 June 30, 2014
Electric operating revenues	$	275,704		$	70,456		$	—		$	346,160
Cost of energy	92,642			16,777			—			109,419
Margin	183,062			53,679			—			236,741
Other operating expenses	106,233			20,411			(3,362		)	123,282
Depreciation and amortization	27,023			12,003			3,137			42,163
Operating income	49,806			21,265			225			71,296
Interest income	2,065			—			(25		)	2,040
Other income (deductions)	5,512			514			(316		)	5,710
Net interest charges	(20,023		)	(6,655		)	(3,294		)	(29,972		)
Segment earnings (loss) before income taxes	37,360			15,124			(3,410		)	49,074
Income taxes (benefit)	13,106			5,590			(2,803		)	15,893
Segment earnings (loss)	24,254			9,534			(607		)	33,181
Valencia non-controlling interest	(3,908		)	—			—			(3,908		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	20,214		$	9,534		$	(607	)	$	29,141
Six Months Ended June 30, 2014
Electric operating revenues	$	538,441		$	136,616		$	—		$	675,057
Cost of energy	189,268			32,765			—			222,033
Margin	349,173			103,851			—			453,024
Other operating expenses	213,957			41,481			(6,593		)	248,845
Depreciation and amortization	54,105			23,844			6,181			84,130
Operating income	81,111			38,526			412			120,049
Interest income	4,193			—			(35		)	4,158
Other income (deductions)	7,180			702			(958		)	6,924
Net interest charges	(39,835		)	(13,252		)	(6,419		)	(59,506		)
Segment earnings (loss) before income taxes	52,649			25,976			(7,000		)	71,625
Income taxes (benefit)	17,189			9,640			(4,516		)	22,313
Segment earnings (loss)	35,460			16,336			(2,484		)	49,312
Valencia non-controlling interest	(7,439		)	—			—			(7,439		)
Subsidiary preferred stock dividends	(264		)	—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	27,757		$	16,336		$	(2,484	)	$	41,609
At June 30, 2014:
Total Assets	$	4,290,529		$	1,208,517		$	105,146		$	5,604,192
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended June 30, 2013
Electric operating revenues	$	279,690		$	67,909		$	—		$	347,599
Cost of energy	91,855			13,804			—			105,659
Margin	187,835			54,105			—			241,940
Other operating expenses	103,482			22,159			(3,207		)	122,434
Depreciation and amortization	26,051			12,279			3,309			41,639
Operating income (loss)	58,302			19,667			(102		)	77,867
Interest income	2,868			—			(35		)	2,833
Other income (deductions)	3,360			486			(2,213		)	1,633
Net interest charges	(19,890		)	(6,759		)	(3,967		)	(30,616		)
Segment earnings (loss) before income taxes	44,640			13,394			(6,317		)	51,717
Income taxes (benefit)	14,943			5,055			336			20,334
Segment earnings (loss)	29,697			8,339			(6,653		)	31,383
Valencia non-controlling interest	(3,573		)	—			—			(3,573		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	25,992		$	8,339		$	(6,653	)	$	27,678
Six Months Ended June 30, 2013
Electric operating revenues	$	537,583		$	127,680		$	—		$	665,263
Cost of energy	183,514			26,851			—			210,365
Margin	354,069			100,829			—			454,898
Other operating expenses	206,643			44,148			(6,910		)	243,881
Depreciation and amortization	51,884			23,960			6,602			82,446
Operating income	95,542			32,721			308			128,571
Interest income	5,541			—			(74		)	5,467
Other income (deductions)	4,766			694			(3,936		)	1,524
Net interest charges	(39,847		)	(14,005		)	(8,062		)	(61,914		)
Segment earnings (loss) before income taxes	66,002			19,410			(11,764		)	73,648
Income taxes (benefit)	21,532			7,345			(574		)	28,303
Segment earnings (loss)	44,470			12,065			(11,190		)	45,345
Valencia non-controlling interest	(6,777		)	—			—			(6,777		)
Subsidiary preferred stock dividends	(264		)	—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	37,429		$	12,065		$	(11,190	)	$	38,304
At June 30, 2013:
Total Assets	$	4,185,189		$	1,155,928		$	62,789		$	5,403,906
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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Pension and Other Postretirement Benefit Plans (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 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	15,082,000	14,071,000
Expected return on plan assets	(9,511,000)	(10,482,000)	(19,022,000)	(20,965,000)
Amortization of net (gain) loss	3,255,000	3,710,000	6,510,000	7,420,000
Amortization of prior service cost	(241,000)	19,000	(483,000)	38,000
Net Periodic Benefit Cost (Income)	1,044,000	282,000	2,087,000	564,000
Defined Benefit Plan, Contributions by Employer		0		60,000,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	61,500,000		61,500,000
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)			5.20%
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)			5.50%
Public Service Company of New Mexico [Member] | OPEB [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	45,000	65,000	91,000	130,000
Interest cost	1,159,000	1,029,000	2,315,000	2,057,000
Expected return on plan assets	(1,410,000)	(1,261,000)	(2,819,000)	(2,522,000)
Amortization of net (gain) loss	556,000	1,061,000	1,113,000	2,121,000
Amortization of prior service cost	(336,000)	(336,000)	(672,000)	(672,000)
Net Periodic Benefit Cost (Income)	14,000	558,000	28,000	1,114,000
Defined Benefit Plan, Contributions by Employer	800,000	1,100,000	1,600,000	1,600,000
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	411,000	360,000
Expected return on plan assets	0	0	0	0
Amortization of net (gain) loss	52,000	58,000	105,000	116,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	257,000	238,000	516,000	476,000
Defined Benefit Plan, Contributions by Employer	400,000	400,000	700,000	800,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	1,500,000		1,500,000
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	1,597,000	1,544,000
Expected return on plan assets	(1,132,000)	(1,212,000)	(2,263,000)	(2,425,000)
Amortization of net (gain) loss	166,000	262,000	333,000	524,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	(168,000)	(178,000)	(333,000)	(357,000)
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)	5.20%
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)	5.50%
Texas-New Mexico Power Company [Member] | OPEB [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	59,000	75,000	119,000	150,000
Interest cost	155,000	141,000	309,000	283,000
Expected return on plan assets	(133,000)	(126,000)	(267,000)	(252,000)
Amortization of net (gain) loss	(31,000)	0	(61,000)	0
Amortization of prior service cost	8,000	14,000	16,000	28,000
Net Periodic Benefit Cost (Income)	58,000	104,000	116,000	209,000
Defined Benefit Plan, Contributions by Employer			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	20,000	18,000
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	20,000	18,000
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

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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		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ (267)	$ 3,006	$ (4,230)	$ (841)
Electric operating revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	(324)	3,269	(4,475)	(1,334)
Cost of energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 57	$ (263)	$ 245	$ 493

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Cash Flows From Operating Activities:
Net Earnings	$ 49,312	$ 45,345
Net earnings	41,609	38,304
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	103,436	103,914
Deferred income tax expense	24,252	27,797
Net unrealized (gains) losses on commodity derivatives	3,187	1,729
Realized (gains) on available-for-sale securities	(7,272)	(4,747)
Stock based compensation expense	3,399	3,198
Other, net	38	255
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(17,543)	(23,021)
Materials, supplies, and fuel stock	6,346	(159)
Other current assets	(20,688)	3,870
Other assets	18,237	6,356
Accounts payable	(29,384)	(7,424)
Accrued interest and taxes	(2,830)	93,077
Other current liabilities	(3,341)	(21,310)
Other liabilities	(3,343)	(68,972)
Net cash flows from operating activities	123,806	159,908
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(160,893)	(153,512)
Proceeds from sales of available-for-sale securities	53,119	76,106
Purchases of available-for-sale securities	(54,338)	(77,882)
Return of principal on PVNGS lessor notes	10,231	10,965
Other, net	750	1,254
Net cash flows from investing activities	(151,131)	(143,069)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(44,200)	1,300
Long-term borrowings	255,000	75,000
Repayment of long-term debt	(125,000)	(9,445)
Cash paid in debt exchange	0	(13,048)
Proceeds from stock option exercise	4,446	11,345
Awards of common stock	(13,939)	(19,741)
Dividends paid	(29,732)	(24,958)
Valencia’s transactions with its owner	(8,189)	(8,675)
Other, net	(1,482)	(2,804)
Net cash flows from financing activities	36,904	8,974
Change in Cash and Cash Equivalents	9,579	25,813
Cash and Cash Equivalents at Beginning of Period	2,533	8,985
Cash and Cash Equivalents at End of Period	12,112	34,798
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	54,712	58,267
Income taxes paid (refunded), net	(2,534)	(95,472)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	(7,909)	(3,375)
Premium on long-term debt incurred in connection with debt exchange	0	36,297
Public Service Company of New Mexico [Member]
Cash Flows From Operating Activities:
Net Earnings	35,460	44,470
Net earnings	28,021	37,693
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	71,327	69,179
Deferred income tax expense	19,716	21,836
Net unrealized (gains) losses on commodity derivatives	3,187	1,729
Realized (gains) on available-for-sale securities	(7,272)	(4,747)
Other, net	193	(876)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(13,885)	(15,841)
Materials, supplies, and fuel stock	6,447	(238)
Other current assets	(22,588)	4,299
Other assets	18,790	6,196
Accounts payable	(26,737)	(5,829)
Accrued interest and taxes	(1,575)	45,380
Other current liabilities	3,943	(23,523)
Other liabilities	(3,193)	(69,059)
Net cash flows from operating activities	83,813	72,976
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(92,567)	(98,673)
Proceeds from sales of available-for-sale securities	53,119	76,106
Purchases of available-for-sale securities	(54,338)	(77,882)
Return of principal on PVNGS lessor notes	10,231	10,965
Other, net	(70)	1,227
Net cash flows from investing activities	(83,625)	(88,257)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(49,200)	(21,100)
Short-term borrowings (repayments), affiliate, net	(32,500)	0
Long-term borrowings	175,000	75,000
Repayment of long-term debt	(75,000)	0
Dividends paid	(264)	(264)
Valencia’s transactions with its owner	(8,189)	(8,675)
Other, net	(700)	(1,169)
Net cash flows from financing activities	9,147	43,792
Change in Cash and Cash Equivalents	9,335	28,511
Cash and Cash Equivalents at Beginning of Period	21	3,958
Cash and Cash Equivalents at End of Period	9,356	32,469
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	36,601	37,845
Income taxes paid (refunded), net	(215)	(44,999)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	(5,595)	817
Texas-New Mexico Power Company [Member]
Cash Flows From Operating Activities:
Net earnings	16,336	12,065
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	25,728	26,034
Deferred income tax expense	6,162	4,348
Other, net	(38)	(10)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(3,658)	(7,180)
Materials, supplies, and fuel stock	(101)	79
Other current assets	(803)	(4,082)
Other assets	(273)	590
Accounts payable	1,381	807
Accrued interest and taxes	(726)	(1,517)
Other current liabilities	2,167	1,278
Other liabilities	365	886
Net cash flows from operating activities	46,540	33,298
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(64,502)	(47,390)
Net cash flows from investing activities	(64,502)	(47,390)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	0	25,000
Short-term borrowings (repayments), net	(4,200)	7,500
Long-term borrowings	80,000	0
Repayment of long-term debt	(50,000)	0
Cash paid in debt exchange	0	(13,048)
Dividends paid	(6,803)	(3,726)
Other, net	(783)	(1,634)
Net cash flows from financing activities	18,214	14,092
Change in Cash and Cash Equivalents	252	0
Cash and Cash Equivalents at Beginning of Period	1	1
Cash and Cash Equivalents at End of Period	253	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	11,847	13,267
Income taxes paid (refunded), net	(304)	696
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	1,038	(886)
Premium on long-term debt incurred in connection with debt exchange	$ 0	$ 36,297

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Earnings Per Share

6 Months Ended

Jun. 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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	29,141	$	27,678	$	41,609	$	38,304
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	110		194		146		202
Average Shares – Basic	79,764		79,848		79,800		79,856
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	464		607		508		661
Average Shares – Diluted	80,228		80,455		80,308		80,517
Net Earnings Per Share of Common Stock:
Basic	$	0.37	$	0.35	$	0.52	$	0.48
Diluted	$	0.36	$	0.34	$	0.52	$	0.48

⁽¹⁾  Excludes the effect of out-of-the-money options for 297,350 shares of common stock at June 30, 2014.

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Accumulated Other Comprehensive Income (Loss) (Tables)

6 Months Ended

Jun. 30, 2014

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the six months ended June 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)	(8,857		)	2,576			176			(6,105		)
Income tax impact of amounts reclassified	3,488			(1,016		)	(61		)	2,411
Other OCI changes (pre-tax)	9,855			—			(153		)	9,702
Income tax impact of other OCI changes	(3,809		)	—			53			(3,756		)
Net change after income taxes	677			1,560			15			2,252
Balance at June 30, 2014	$	26,425		$	(82,065	)	$	(248	)	$	(55,888	)

PNM
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	—	$	(57,877	)
Amounts reclassified from AOCI (pre-tax)	(8,857		)	2,576			—		(6,281		)
Income tax impact of amounts reclassified	3,488			(1,016		)	—		2,472
Other OCI changes (pre-tax)	9,855			—			—		9,855
Income tax impact of other OCI changes	(3,809		)	—			—		(3,809		)
Net change after income taxes	677			1,560			—		2,237
Balance at June 30, 2014	$	26,425		$	(82,065	)	$	—	$	(55,640	)

TNMP
Balance at December 31, 2013	$	—	$	—	$	(263	)	$	(263	)
Amounts reclassified from AOCI (pre-tax)	—		—		176			176
Income tax impact of amounts reclassified	—		—		(61		)	(61		)
Other OCI changes (pre-tax)	—		—		(153		)	(153		)
Income tax impact of other OCI changes	—		—		53			53
Net change after income taxes	—		—		15			15
Balance at June 30, 2014	$	—	$	—	$	(248	)	$	(248	)

	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)	(6,854		)	3,182			99			(3,573		)
Income tax impact of amounts reclassified	2,714			(1,262		)	(35		)	1,417
Other OCI changes (pre-tax)	8,591			—			3			8,594
Income tax impact of other OCI changes	(3,401		)	—			(1		)	(3,402		)
Net change after income taxes	1,050			1,920			66			3,036
Balance at June 30, 2013	$	17,456		$	(95,900	)	$	(150	)	$	(78,594	)

PNM
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	—	$	(81,414	)
Amounts reclassified from AOCI (pre-tax)	(6,854		)	3,182			—		(3,672		)
Income tax impact of amounts reclassified	2,714			(1,262		)	—		1,452
Other OCI changes (pre-tax)	8,591			—			—		8,591
Income tax impact of other OCI changes	(3,401		)	—			—		(3,401		)
Net change after income taxes	1,050			1,920			—		2,970
Balance at June 30, 2013	$	17,456		$	(95,900	)	$	—	$	(78,444	)

TNMP
Balance at December 31, 2012	$	—	$	—	$	(216	)	$	(216	)
Amounts reclassified from AOCI (pre-tax)	—		—		99			99
Income tax impact of amounts reclassified	—		—		(35		)	(35		)
Other OCI changes (pre-tax)	—		—		3			3
Income tax impact of other OCI changes	—		—		(1		)	(1		)
Net change after income taxes	—		—		66			66
Balance at June 30, 2013	$	—	$	—	$	(150	)	$	(150	)

XML

Variable Interest Entities (Details) (USD $)	3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended					1 Months Ended	3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended						3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Jun. 30, 2014 Public Service Company of New Mexico [Member]	Jun. 30, 2013 Public Service Company of New Mexico [Member]	Jun. 30, 2014 Public Service Company of New Mexico [Member]	Jun. 30, 2013 Public Service Company of New Mexico [Member]	Dec. 31, 2013 Public Service Company of New Mexico [Member]	Jun. 30, 2014 Palo Verde Nuclear Generating Station [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Palo Verde Nuclear Generating Station [Member] Property Lease Guarantee [Member] Maximum [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2012 Delta [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Delta [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Delta [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member]	Dec. 31, 2013 Delta [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Valencia [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2013 Valencia [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Valencia [Member] Public Service Company of New Mexico [Member]	Jun. 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] Purchased Through May 30, 2028 [Member] Public Service Company of New Mexico [Member] MW	Jun. 30, 2014 Variable Interest Entity, Not Primary Beneficiary [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Delta [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2013 Delta [Member] Public Service Company of New Mexico [Member]	Jun. 30, 2014 Delta [Member] Public Service Company of New Mexico [Member]	Jun. 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	$ 4,700,000	$ 9,600,000	$ 9,400,000					$ 1,600,000	$ 1,600,000	$ 3,200,000	$ 3,200,000
Long Term Contract For Purchase of Electric Power Variable Charges																			500,000	200,000	700,000	300,000					300,000	400,000	500,000	600,000
Variable Interest Entity, Statement Of Operation [Abstract]
Operating revenues																			5,307,000	4,922,000	10,238,000	9,697,000
Operating expenses																			(1,399,000)	(1,349,000)	(2,799,000)	(2,920,000)
Earnings attributable to non-controlling interest	3,908,000	3,573,000	7,439,000	6,777,000		3,908,000	3,573,000	7,439,000	6,777,000										3,908,000	3,573,000	7,439,000	6,777,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	446,825,000		446,825,000		401,539,000	393,099,000		393,099,000		348,502,000									3,232,000		3,232,000		2,658,000
Net property, plant, and equipment																			73,729,000		73,729,000		75,137,000
Total assets	5,604,192,000	5,403,906,000	5,604,192,000	5,403,906,000	5,500,210,000	4,290,529,000		4,290,529,000		4,227,616,000									76,961,000		76,961,000		77,795,000
Current liabilities	486,869,000		486,869,000		492,671,000	226,303,000		226,303,000		357,266,000									682,000		682,000		766,000
Owners’ equity – non-controlling interest	76,279,000		76,279,000		77,029,000	76,279,000		76,279,000		77,029,000									76,279,000		76,279,000		77,029,000
Long term contract option to purchase, ownership percentage																			50.00%
Long term contract option to purchase, estimated purchase price																								85,000,000
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, 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											36,500,000
Operating leases, future minimum payments due, renewal term																										145,200,000
Loss Contingency, Range of Possible Loss, Portion Not Accrued												144,700,000.0
Operating Leases, Future Minimum Payments Due, Next Six Months											26,000,000
Period of Long Term Contract For Purchase of Electric Power Fixed Costs																											20 years
Long Term Contract for Purchase of Electric Power Aggregate Amount of Contract Remaining																											36,200,000		36,200,000
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		14,600,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets														22,400,000		22,400,000		23,700,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment														19,000,000		19,000,000		20,300,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities														16,500,000		16,500,000		18,200,000
Revenues														2,500,000	2,200,000	4,300,000	4,000,000
Net earnings	$ 29,141,000	$ 27,678,000	$ 41,609,000	$ 38,304,000		$ 20,346,000	$ 26,124,000	$ 28,021,000	$ 37,693,000					$ 300,000	$ 100,000	$ 600,000	$ 300,000

XML

Regulatory and Rate Matters

6 Months Ended

Jun. 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). The NMPRC has scheduled a public hearing on the plan to begin September 11, 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.

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.

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.

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.

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. A public hearing on the stipulation was held on February 25, 2014. The Hearing Examiner recommended approval of the settlement in its entirety to the NMPRC. 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.

Applications for Approvals to Purchase Delta

As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Report on Form 10-K, PNM entered in to an agreement to purchase 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

As discussed in Note 11, on December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. In that application, PNM also sought approval to recover the net book value of SJGS Units 2 and 3 at the date of retirement, for a CCN to include PNM’s share of PVNGS Unit 3 as a resource to serve New Mexico consumers, authority to install SNCRs on SJGS Units 1 and 4, and a CCN to exchange 78 MW in SJGS Unit 3 for the same amount of capacity in SJGS Unit 4. Based upon a non-binding agreement in principle among the SJGS owners, PNM made a filing on July 1, 2014 that advised the NMPRC that it proposes to acquire an additional 132 MW of SJGS Unit 4, at no initial cost, effective December 31, 2017, rather than the exchange of 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 contemplated in its initial application. The public hearing in the NMPRC case is now scheduled to begin on October 6, 2014. PNM is currently requesting the NMPRC take action on this case by the end of February 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.

Four Corners Right of First Refusal

On June 16, 2014, PNM notified the NMPRC that it intended to provide a waiver of its right of first refusal (“ROFR”) to acquire some or all of the 7% interest in Four Corners held by EPE that is intended to be acquired by APS. On July 1, 2014, the staff of the NMPRC filed a petition asking for an inquiry by the NMPRC into whether it was in the public interest for PNM to waive its ROFR, because the cost of this capacity may be less than the cost of other resources that PNM has proposed or is considering as replacement capacity for the capacity that PNM has proposed to retire at SJGS (Note 11). The petition requested the NMPRC to initiate an inquiry, direct PNM not to waive its ROFR, and direct PNM to respond to the questions that staff attached to its petition. In its July 7, 2014 response to the staff’s petition, PNM stated that it will not file a waiver of its ROFR prior to the earlier of a NMPRC order disposing of the matter or the expiration of the 120 day period allowed for the exercise of the ROFR. The response explained that the capacity under discussion is still held by EPE, which has regulated operations in New Mexico, and EPE has not yet filed with the NMPRC for abandonment of that capacity.  The response also explained that if the Four Corners capacity was no longer an economical resource for EPE to hold, then it likely would not be an economical resource for PNM to acquire, and it would increase PNM’s dependency on coal-fired generation.  The NMPRC has not acted on the staff’s petition.

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 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 2013 revenues for power sold under the Gallup contract were $2.9 million and $6.1 million in the three and 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 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 monthly 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 does not expect the settlement 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 parties have agreed on terms that would resolve TNMP’s application and are preparing settlement documents for submission to the PUCT.

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 request, which is subject to PUCT approval, asks that new rates become effective on September 1, 2014.