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, 2015

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 24, 2015, 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 24, 2015 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 24, 2015 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	75
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	106
ITEM 4. CONTROLS AND PROCEDURES	109
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	109
ITEM 1A. RISK FACTORS	110
ITEM 5. OTHER INFORMATION	110
ITEM 6. EXHIBITS	111
SIGNATURE	112

3

GLOSSARY

Definitions:
ABCWUA	Albuquerque-Bernalillo County Water Utility Authority
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, the operator and a co-owner of PVNGS and Four Corners
ASU	Accounting Standards Update
BACT	Best Available Control Technology
BART	Best Available Retrofit Technology
BDT	Balanced Draft 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
COFA	Capacity Option and Funding Agreement
CSA	Coal Supply Agreement
CTC	Competition Transition Charge
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
Delta	Delta-Person Generating Station, now known as Rio Bravo
DOE	United States Department of Energy
DOI	United States Department of Interior
EGU	Electric Generating Unit
EIB	New Mexico Environmental Improvement Board
EIP	Eastern Interconnection Project
EIS	Environmental Impact Statement
EPA	United States Environmental Protection Agency
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
FTY	Future Test Year
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

4

ISFSI	Independent Spent Fuel Storage Installation
KW	Kilowatt
KWh	Kilowatt Hour
Lightning Dock Geothermal	Lightning Dock geothermal power facility, also known as the Dale Burgett Geothermal Plant
Lordsburg	Lordsburg Generating Station
Luna	Luna Energy Facility
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.
NEPA	National Environmental Policy Act
NERC	North American Electric Reliability Corporation
New Mexico Wind	New Mexico Wind Energy Center
NMAG	New Mexico Attorney General
NMED	New Mexico Environment Department
NMIEC	New Mexico Industrial Energy Consumers Inc.
NMPRC	New Mexico Public Regulation Commission
NOx	Nitrogen Oxides
NOPR	Notice of Proposed Rulemaking
NRC	United States Nuclear Regulatory Commission
NSPS	New Source Performance Standards
NSR	New Source Review
OCI	Other Comprehensive Income
OPEB	Other Post Employment Benefits
OSM	United States Office of Surface Mining Reclamation and Enforcement
PCRBs	Pollution Control Revenue Bonds
PNM	Public Service Company of New Mexico and Subsidiaries
PNM 2013 Term Loan Agreement	PNM’s $75.0 Million Unsecured Term Loan
PNM 2014 Term Loan Agreement	PNM’s $175.0 Million Unsecured Term Loan
PNM Multi-draw Term Loan	PNM’s $125.0 Million Unsecured Multi-draw 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
PNMR	PNM Resources, Inc. and Subsidiaries
PNMR 2015 Term Loan Agreement	PNMR’s $150.0 Million Unsecured Term Loan
PNMR Development	PNMR Development and Management Company, an unregulated wholly-owned subsidiary of PNMR
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

5

PPA	Power Purchase Agreement
PSD	Prevention of Significant Deterioration
PUCT	Public Utility Commission of Texas
PV	Photovoltaic
PVNGS	Palo Verde Nuclear Generating Station
RA	San Juan Project Restructuring Agreement
RCRA	Resource Conservation and Recovery Act
RCT	Reasonable Cost Threshold
REA	New Mexico’s Renewable Energy Act of 2004
REC	Renewable Energy Certificates
Red Mesa Wind	Red Mesa Wind Energy Center
REP	Retail Electricity Provider
Rio Bravo	Rio Bravo Generating Station, formerly known as Delta
RMC	Risk Management Committee
ROE	Return on Equity
RPS	Renewable Energy Portfolio Standard
RSIP	Revised State Implementation Plan
S&P	Standard and Poor’s Ratings Services
SCE	Southern California Edison Company
SCPPA	Southern California Public Power Authority
SCR	Selective Catalytic Reduction
SEC	United States Securities and Exchange Commission
SIP	State Implementation Plan
SJCC	San Juan Coal Company
SJGS	San Juan Generating Station
SJPPA	San Juan Project Participation Agreement
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
SPS	Southwestern Public Service Company
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 Secured Revolving Credit Facility
TNP	TNP Enterprises, Inc. and Subsidiaries
Tucson	Tucson Electric Power Company
UG-CSA	Underground Coal Sales Agreement
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,
	2015			2014			2015			2014
	(In thousands, except per share amounts)
Electric Operating Revenues	$	352,887		$	346,160		$	685,755		$	675,057
Operating Expenses:
Cost of energy	114,038			109,419			229,683			222,033
Administrative and general	39,928			45,235			83,787			89,093
Energy production costs	44,790			45,846			87,459			93,134
Regulatory disallowances	1,529			—			1,744			—
Depreciation and amortization	46,049			42,163			91,510			84,130
Transmission and distribution costs	16,868			16,068			33,354			32,974
Taxes other than income taxes	17,271			16,133			36,234			33,644
Total operating expenses	280,473			274,864			563,771			555,008
Operating income	72,414			71,296			121,984			120,049
Other Income and Deductions:
Interest income	1,941			2,040			3,691			4,158
Gains on available-for-sale securities	5,556			4,699			9,580			7,272
Other income	5,717			3,180			10,679			4,754
Other (deductions)	(3,707		)	(2,169		)	(7,370		)	(5,102		)
Net other income and deductions	9,507			7,750			16,580			11,082
Interest Charges	28,913			29,972			59,186			59,506
Earnings before Income Taxes	53,008			49,074			79,378			71,625
Income Taxes	17,353			15,893			25,870			22,313
Net Earnings	35,655			33,181			53,508			49,312
(Earnings) Attributable to Valencia Non-controlling Interest	(3,850		)	(3,908		)	(7,231		)	(7,439		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(264		)	(264		)
Net Earnings Attributable to PNMR	$	31,673		$	29,141		$	46,013		$	41,609
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.40		$	0.37		$	0.58		$	0.52
Diluted	$	0.40		$	0.36		$	0.57		$	0.52
Dividends Declared per Common Share	$	0.200		$	0.185		$	0.400		$	0.370

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,
	2015			2014			2015			2014
	(In thousands)
Net Earnings	$	35,655		$	33,181		$	53,508		$	49,312
Other Comprehensive Income (Loss):
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit of $266, $(2,602), $(2,413) and $(3,809)	(413		)	3,999			3,744			6,046
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $3,278, $2,210, $4,913 and $3,488	(5,087		)	(3,397		)	(7,624		)	(5,369		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(583), $(508), $(1,166) and $(1,016)	905			780			1,810			1,560
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $0, $0 and $53	—			—			—			(100		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $0, $(42), $0 and $(61)	—			79			—			115
Total Other Comprehensive Income (Loss)	(4,595		)	1,461			(2,070		)	2,252
Comprehensive Income	31,060			34,642			51,438			51,564
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,850		)	(3,908		)	(7,231		)	(7,439		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(264		)	(264		)
Comprehensive Income Attributable to PNMR	$	27,078		$	30,602		$	43,943		$	43,861

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,
	2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	53,508		$	49,312
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	108,891			103,436
Deferred income tax expense	26,675			24,252
Net unrealized (gains) losses on commodity derivatives	6,127			3,187
Realized (gains) on available-for-sale securities	(9,580		)	(7,272		)
Stock based compensation expense	2,761			3,399
Regulatory disallowances	1,744			—
Other, net	(1,926		)	38
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(20,899		)	(17,543		)
Materials, supplies, and fuel stock	(8,285		)	6,346
Other current assets	16,342			(20,688		)
Other assets	8,062			18,237
Accounts payable	(20,777		)	(29,384		)
Accrued interest and taxes	(4,380		)	(2,830		)
Other current liabilities	(10,195		)	(3,341		)
Other liabilities	(38,394		)	(3,343		)
Net cash flows from operating activities	109,674			123,806
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(232,964		)	(160,893		)
Proceeds from sales of available-for-sale securities	94,522			53,119
Purchases of available-for-sale securities	(94,905		)	(54,338		)
Return of principal on PVNGS lessor notes	14,188			10,231
Other, net	2,694			750
Net cash flows from investing activities	(216,465		)	(151,131		)

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,
	2015			2014
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	82,000			(44,200		)
Long-term borrowings	214,300			255,000
Repayment of long-term debt	(158,066		)	(125,000		)
Proceeds from stock option exercise	7,347			4,446
Awards of common stock	(18,814		)	(13,939		)
Dividends paid	(32,125		)	(29,732		)
Valencia’s transactions with its owner	(7,614		)	(8,189		)
Other, net	(2,107		)	(1,482		)
Net cash flows from financing activities	84,921			36,904
Change in Cash and Cash Equivalents	(21,870		)	9,579
Cash and Cash Equivalents at Beginning of Period	28,274			2,533
Cash and Cash Equivalents at End of Period	$	6,404		$	12,112
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	56,309		$	54,712
Income taxes paid (refunded), net	$	(1,231	)	$	(2,534	)
Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(743	)	$	(7,909	)

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, 2015		December 31, 2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	6,404	$	28,274
Accounts receivable, net of allowance for uncollectible accounts of $1,363 and $1,466	94,703		87,038
Unbilled revenues	75,527		63,719
Other receivables	30,027		39,857
Materials, supplies, and fuel stock	71,913		63,628
Regulatory assets	23,142		47,855
Commodity derivative instruments	4,550		11,232
Income taxes receivable	5,934		6,360
Current portion of accumulated deferred income taxes	26,383		26,383
Other current assets	71,482		58,471
Total current assets	410,065		432,817
Other Property and Investments:
Investment in PVNGS lessor notes	—		9,538
Available-for-sale securities	253,550		250,145
Other investments	507		1,762
Non-utility property	3,404		3,406
Total other property and investments	257,461		264,851
Utility Plant:
Plant in service and plant held for future use	6,085,078		5,941,581
Less accumulated depreciation and amortization	2,017,711		1,939,760
	4,067,367		4,001,821
Construction work in progress	261,049		190,389
Nuclear fuel, net of accumulated amortization of $45,138 and $44,507	81,275		77,796
Net utility plant	4,409,691		4,270,006
Deferred Charges and Other Assets:
Regulatory assets	474,426		491,007
Goodwill	278,297		278,297
Other deferred charges	97,078		92,347
Total deferred charges and other assets	849,801		861,651
	$	5,927,018	$	5,829,325

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, 2015			December 31, 2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	187,600		$	105,600
Current installments of long-term debt	300,000			333,066
Accounts payable	88,509			110,029
Customer deposits	12,711			12,555
Accrued interest and taxes	49,452			53,863
Regulatory liabilities	2,202			1,703
Commodity derivative instruments	1,153			1,209
Dividends declared	132			16,063
Other current liabilities	59,345			70,194
Total current liabilities	701,104			704,282
Long-term Debt	1,731,158			1,642,024
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	918,519			891,111
Regulatory liabilities	470,558			466,143
Asset retirement obligations	108,406			104,170
Accrued pension liability and postretirement benefit cost	70,583			110,738
Commodity derivative instruments	—			477
Other deferred credits	101,282			103,759
Total deferred credits and other liabilities	1,669,348			1,676,398
Total liabilities	4,101,610			4,022,704
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)	1,165,003			1,173,845
Accumulated other comprehensive income (loss), net of income taxes	(63,825		)	(61,755		)
Retained earnings	639,538			609,456
Total PNMR common stockholders’ equity	1,740,716			1,721,546
Non-controlling interest in Valencia	73,163			73,546
Total equity	1,813,879			1,795,092
	$	5,927,018		$	5,829,325

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, 2014	$	1,173,845		$	(61,755	)	$	609,456		$	1,721,546		$	73,546		$	1,795,092
Proceeds from stock option exercise	7,347			—			—			7,347			—			7,347
Awards of common stock	(18,814		)	—			—			(18,814		)	—			(18,814		)
Excess tax (shortfall) from stock-based payment arrangements	(136		)	—			—			(136		)	—			(136		)
Stock based compensation expense	2,761			—			—			2,761			—			2,761
Valencia’s transactions with its owner	—			—			—			—			(7,614		)	(7,614		)
Net earnings before subsidiary preferred stock dividends	—			—			46,277			46,277			7,231			53,508
Subsidiary preferred stock dividends	—			—			(264		)	(264		)	—			(264		)
Total other comprehensive income	—			(2,070		)	—			(2,070		)	—			(2,070		)
Dividends declared on common stock	—			—			(15,931		)	(15,931		)	—			(15,931		)
Balance at June 30, 2015	$	1,165,003		$	(63,825	)	$	639,538		$	1,740,716		$	73,163		$	1,813,879

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,
	2015			2014			2015			2014
	(In thousands)
Electric Operating Revenues	$	275,450		$	275,704		$	537,390		$	538,441
Operating Expenses:
Cost of energy	95,728			92,642			193,594			189,268
Administrative and general	36,956			40,603			76,524			79,213
Energy production costs	44,790			45,846			87,459			93,134
Regulatory disallowances	1,529			—			1,744			—
Depreciation and amortization	29,002			27,023			57,405			54,105
Transmission and distribution costs	10,272			10,183			21,040			21,510
Taxes other than income taxes	9,994			9,601			20,790			20,100
Total operating expenses	228,271			225,898			458,556			457,330
Operating income	47,179			49,806			78,834			81,111
Other Income and Deductions:
Interest income	1,946			2,065			3,717			4,193
Gains on available-for-sale securities	5,556			4,699			9,580			7,272
Other income	4,901			2,443			8,292			3,555
Other (deductions)	(3,011		)	(1,630		)	(4,615		)	(3,647		)
Net other income and deductions	9,392			7,577			16,974			11,373
Interest Charges	19,681			20,023			39,640			39,835
Earnings before Income Taxes	36,890			37,360			56,168			52,649
Income Taxes	11,527			13,106			17,302			17,189
Net Earnings	25,363			24,254			38,866			35,460
(Earnings) Attributable to Valencia Non-controlling Interest	(3,850		)	(3,908		)	(7,231		)	(7,439		)
Net Earnings Attributable to PNM	21,513			20,346			31,635			28,021
Preferred Stock Dividends Requirements	(132		)	(132		)	(264		)	(264		)
Net Earnings Available for PNM Common Stock	$	21,381		$	20,214		$	31,371		$	27,757

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,
	2015			2014			2015			2014
	(In thousands)
Net Earnings	$	25,363		$	24,254		$	38,866		$	35,460
Other Comprehensive Income (Loss):
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit of $266, $(2,602), $(2,413) and $(3,809)	(413		)	3,999			3,744			6,046
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $3,278, $2,210, $4,913 and $3,488	(5,087		)	(3,397		)	(7,624		)	(5,369		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(583), $(508), $(1,166) and $(1,016)	905			780			1,810			1,560
Total Other Comprehensive Income (Loss)	(4,595		)	1,382			(2,070		)	2,237
Comprehensive Income	20,768			25,636			36,796			37,697
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,850		)	(3,908		)	(7,231		)	(7,439		)
Comprehensive Income Attributable to PNM	$	16,918		$	21,728		$	29,565		$	30,258

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,
	2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	38,866		$	35,460
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	73,701			71,327
Deferred income tax expense	18,464			19,716
Net unrealized (gains) losses on commodity derivatives	6,127			3,187
Realized (gains) on available-for-sale securities	(9,580		)	(7,272		)
Regulatory disallowances	1,744			—
Other, net	(2,958		)	193
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(15,283		)	(13,885		)
Materials, supplies, and fuel stock	(7,860		)	6,447
Other current assets	15,882			(22,588		)
Other assets	7,568			18,790
Accounts payable	(21,315		)	(26,737		)
Accrued interest and taxes	412			(1,575		)
Other current liabilities	(3,259		)	3,943
Other liabilities	(34,729		)	(3,193		)
Net cash flows from operating activities	67,780			83,813
Cash Flows From Investing Activities:
Utility plant additions	(172,937		)	(92,567		)
Proceeds from sales of available-for-sale securities	94,522			53,119
Purchases of available-for-sale securities	(94,905		)	(54,338		)
Return of principal on PVNGS lessor notes	14,188			10,231
Other, net	2,859			(70		)
Net cash flows from investing activities	(156,273		)	(83,625		)

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,
	2015			2014
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	51,100			(49,200		)
Short-term borrowings (repayments), affiliate, net	—			(32,500		)
Long-term borrowings	64,300			175,000
Repayment of long-term debt	(39,300		)	(75,000		)
Valencia’s transactions with its owner	(7,614		)	(8,189		)
Dividends paid	(264		)	(264		)
Other, net	(1,659		)	(700		)
Net cash flows from financing activities	66,563			9,147
Change in Cash and Cash Equivalents	(21,930		)	9,335
Cash and Cash Equivalents at Beginning of Period	25,480			21
Cash and Cash Equivalents at End of Period	$	3,550		$	9,356
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	36,977		$	36,601
Income taxes paid (refunded), net	$	(1,450	)	$	(215	)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	$	2,813		$	(5,595	)

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, 2015		December 31, 2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	3,550	$	25,480
Accounts receivable, net of allowance for uncollectible accounts of $1,363 and $1,466	70,342		67,622
Unbilled revenues	65,277		54,140
Other receivables	29,751		37,622
Affiliate receivables	10,746		8,853
Materials, supplies, and fuel stock	68,719		60,859
Regulatory assets	17,699		43,980
Commodity derivative instruments	4,550		11,232
Income taxes receivable	5,816		6,105
Current portion of accumulated deferred income taxes	12,418		12,418
Other current assets	64,082		53,095
Total current assets	352,950		381,406
Other Property and Investments:
Investment in PVNGS lessor notes	—		9,538
Available-for-sale securities	253,550		250,145
Other investments	265		397
Non-utility property	96		96
Total other property and investments	253,911		260,176
Utility Plant:
Plant in service and plant held for future use	4,698,267		4,581,066
Less accumulated depreciation and amortization	1,542,034		1,486,406
	3,156,233		3,094,660
Construction work in progress	217,860		169,673
Nuclear fuel, net of accumulated amortization of $45,138 and $44,507	81,275		77,796
Net utility plant	3,455,368		3,342,129
Deferred Charges and Other Assets:
Regulatory assets	344,472		357,045
Goodwill	51,632		51,632
Other deferred charges	85,946		81,264
Total deferred charges and other assets	482,050		489,941
	$	4,544,279	$	4,473,652

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, 2015			December 31, 2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	51,100		$	—
Current installments of long-term debt	300,000			214,300
Accounts payable	67,553			86,055
Affiliate payables	20,991			18,232
Customer deposits	12,711			12,555
Accrued interest and taxes	29,817			29,298
Regulatory liabilities	2,202			1,703
Commodity derivative instruments	1,153			1,209
Dividends declared	20,132			132
Other current liabilities	45,276			52,053
Total current liabilities	550,935			415,537
Long-term Debt	1,215,676			1,276,357
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	734,871			715,814
Regulatory liabilities	431,552			425,481
Asset retirement obligations	107,377			103,182
Accrued pension liability and postretirement benefit cost	63,340			102,850
Commodity derivative instruments	—			477
Other deferred credits	83,679			86,023
Total deferred credits and liabilities	1,420,819			1,433,827
Total liabilities	3,187,430			3,125,721
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	(63,825		)	(61,755		)
Retained earnings	274,206			262,835
Total PNM common stockholder’s equity	1,272,157			1,262,856
Non-controlling interest in Valencia	73,163			73,546
Total equity	1,345,320			1,336,402
	$	4,544,279		$	4,473,652

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, 2014	$	1,061,776	$	(61,755	)	$	262,835		$	1,262,856		$	73,546		$	1,336,402
Valencia’s transactions with its owner	—		—			—			—			(7,614		)	(7,614		)
Net earnings	—		—			31,635			31,635			7,231			38,866
Total other comprehensive income	—		(2,070		)	—			(2,070		)	—			(2,070		)
Dividends declared on preferred stock	—		—			(264		)	(264		)	—			(264		)
Dividends declared on common stock	—		—			(20,000		)	(20,000		)	—			(20,000		)
Balance at June 30, 2015	$	1,061,776	$	(63,825	)	$	274,206		$	1,272,157		$	73,163		$	1,345,320

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,
	2015		2014			2015			2014
	(In thousands)
Electric Operating Revenues	$	77,437	$	70,456		$	148,365		$	136,616
Operating Expenses:
Cost of energy	18,310		16,777			36,089			32,765
Administrative and general	8,042		8,768			17,875			18,609
Depreciation and amortization	13,591		12,003			27,049			23,844
Transmission and distribution costs	6,596		5,885			12,314			11,464
Taxes other than income taxes	6,169		5,758			12,378			11,408
Total operating expenses	52,708		49,191			105,705			98,090
Operating income	24,729		21,265			42,660			38,526
Other Income and Deductions:
Other income	792		586			2,332			1,006
Other (deductions)	1		(72		)	(248		)	(304		)
Net other income and deductions	793		514			2,084			702
Interest Charges	6,856		6,655			13,781			13,252
Earnings before Income Taxes	18,666		15,124			30,963			25,976
Income Taxes	6,801		5,590			11,404			9,640
Net Earnings	$	11,865	$	9,534		$	19,559		$	16,336

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,
	2015		2014		2015		2014
	(In thousands)
Net Earnings	$	11,865	$	9,534	$	19,559	$	16,336
Other Comprehensive Income:
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $0, $0 and $53	—		—		—		(100		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $0, $(42), $0 and $(61)	—		79		—		115
Total Other Comprehensive Income	—		79		—		15
Comprehensive Income	$	11,865	$	9,613	$	19,559	$	16,351

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,
	2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	19,559		$	16,336
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	27,839			25,728
Deferred income tax expense	6,175			6,162
Other, net	(90		)	(38		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(5,616		)	(3,658		)
Materials and supplies	(425		)	(101		)
Other current assets	(1,264		)	(803		)
Other assets	68			(273		)
Accounts payable	385			1,381
Accrued interest and taxes	(173		)	(726		)
Other current liabilities	2,530			2,167
Other liabilities	(4,132		)	365
Net cash flows from operating activities	44,856			46,540
Cash Flows From Investing Activities:
Utility plant additions	(50,256		)	(64,502		)
Net cash flows from investing activities	(50,256		)	(64,502		)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	24,000			—
Short-term borrowings (repayments) – affiliate, net	(18,600		)	(4,200		)
Long-term borrowings	—			80,000
Repayment of long-term debt	—			(50,000		)
Dividends paid	—			(6,803		)
Other, net	—			(783		)
Net cash flows from financing activities	5,400			18,214
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	$	1		$	253
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	12,990		$	11,847
Income taxes paid (refunded), net	$	950		$	(304	)
Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(2,311	)	$	1,038

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, 2015		December 31, 2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable	24,361		19,416
Unbilled revenues	10,250		9,579
Other receivables	712		2,063
Materials and supplies	3,194		2,769
Regulatory assets	5,443		3,875
Current portion of accumulated deferred income taxes	6,398		6,398
Other current assets	2,117		938
Total current assets	52,476		45,039
Other Property and Investments:
Other investments	242		242
Non-utility property	2,240		2,240
Total other property and investments	2,482		2,482
Utility Plant:
Plant in service and plant held for future use	1,207,232		1,182,112
Less accumulated depreciation and amortization	391,169		375,407
	816,063		806,705
Construction work in progress	32,149		16,538
Net utility plant	848,212		823,243
Deferred Charges and Other Assets:
Regulatory assets	129,954		133,962
Goodwill	226,665		226,665
Other deferred charges	9,073		8,850
Total deferred charges and other assets	365,692		369,477
	$	1,268,862	$	1,240,241

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, 2015		December 31, 2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	29,000	$	5,000
Short-term debt – affiliate	4,100		22,700
Accounts payable	12,277		14,203
Affiliate payables	4,123		2,469
Accrued interest and taxes	28,401		28,574
Dividends declared	7,694		—
Other current liabilities	3,116		2,271
Total current liabilities	88,711		75,217
Long-term Debt	365,482		365,667
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	224,260		217,945
Regulatory liabilities	39,006		40,662
Asset retirement obligations	884		848
Accrued pension liability and postretirement benefit cost	7,243		7,888
Other deferred credits	6,746		7,349
Total deferred credits and other liabilities	278,139		274,692
Total liabilities	732,332		715,576
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
Retained earnings	132,300		120,435
Total common stockholder’s equity	536,530		524,665
	$	1,268,862	$	1,240,241

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		Retained Earnings			Total Common Stockholder’s Equity
	(In thousands)
Balance at December 31, 2014	$	64	$	404,166	$	120,435		$	524,665
Net earnings	—		—		19,559			19,559
Dividends declared on common stock	—		—		(7,694		)	(7,694		)
Balance at June 30, 2015	$	64	$	404,166	$	132,300		$	536,530

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, 2015 and December 31, 2014 and the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2015 and 2014, and the consolidated cash flows for the six months ended June 30, 2015 and 2014. 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 2014 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2015 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 2014 Annual Reports on Form 10-K.

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

Principles of Consolidation

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

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. 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 $0.200 per share in July 2015 and $0.185 in July

27

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2014, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

PNM and TNMP declared cash dividends on common stock to PNMR of $20.0 million and $7.7 million in June 2015 that were paid on July 1, 2015. PNM declared no dividends on its common stock in the six months ended June 30, 2014. TNMP declared and paid cash dividends of $6.8 million in the six months ended June 30, 2014.

New Accounting Pronouncements

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

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

On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard was to be 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. On July 9, 2015, the FASB approved a one-year deferral in the effective date of ASU 2014-09, with early adoption as of the original effective date permitted. 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 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

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

Accounting Standards Update 2015-03 - Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs

On April 7, 2015, the FASB issued ASU No. 2015-03, which requires that issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction of the carrying amount of that debt and not as an asset. The ASU is effective for the Company for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is evaluating the impacts of the ASU. Currently, unamortized debt issuance costs that would be reclassified are included in other deferred charges on the Condensed Consolidated Balance Sheets and, at June 30, 2015, amounted to $11.8 million for PNMR, $7.5 million for PNM, and $4.2 million for TNMP.

Accounting Standards Update 2015-07 - Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)

On May 1, 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The new standard is effective for reporting periods beginning after December 31, 2016, with early adoption permitted. Once adopted, the update is required to be applied on a retrospective basis for all periods presented. The Company is in the process of analyzing this new standard; however, it is not expected to have a material impact on the financial statements other than the disclosure and presentation of certain investments of the Company’s employee benefit plans that are measured using the net asset value practical expedient.

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,
	2015		2014		2015		2014
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	31,673	$	29,141	$	46,013	$	41,609
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	99		110		105		146
Average Shares – Basic	79,753		79,764		79,759		79,800
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	380		464		384		508
Average Shares – Diluted	80,133		80,228		80,143		80,308
Net Earnings Per Share of Common Stock:
Basic	$	0.40	$	0.37	$	0.58	$	0.52
Diluted	$	0.40	$	0.36	$	0.57	$	0.52

⁽¹⁾  Excludes the effect of out-of-the-money options for 245,950 shares of common stock at June 30, 2015.

(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, 2015
Electric operating revenues	$	275,450		$	77,437		$	—		$	352,887
Cost of energy	95,728			18,310			—			114,038
Margin	179,722			59,127			—			238,849
Other operating expenses	103,541			20,807			(3,962		)	120,386
Depreciation and amortization	29,002			13,591			3,456			46,049
Operating income (loss)	47,179			24,729			506			72,414
Interest income	1,946			—			(5		)	1,941
Other income (deductions)	7,446			793			(673		)	7,566
Net interest charges	(19,681		)	(6,856		)	(2,376		)	(28,913		)
Segment earnings (loss) before income taxes	36,890			18,666			(2,548		)	53,008
Income taxes (benefit)	11,527			6,801			(975		)	17,353
Segment earnings (loss)	25,363			11,865			(1,573		)	35,655
Valencia non-controlling interest	(3,850		)	—			—			(3,850		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	21,381		$	11,865		$	(1,573	)	$	31,673
Six Months Ended June 30, 2015
Electric operating revenues	$	537,390		$	148,365		$	—		$	685,755
Cost of energy	193,594			36,089			—			229,683
Margin	343,796			112,276			—			456,072
Other operating expenses	207,557			42,567			(7,546		)	242,578
Depreciation and amortization	57,405			27,049			7,056			91,510
Operating income	78,834			42,660			490			121,984
Interest income	3,717			—			(26		)	3,691
Other income (deductions)	13,257			2,084			(2,452		)	12,889
Net interest charges	(39,640		)	(13,781		)	(5,765		)	(59,186		)
Segment earnings (loss) before income taxes	56,168			30,963			(7,753		)	79,378
Income taxes (benefit)	17,302			11,404			(2,836		)	25,870
Segment earnings (loss)	38,866			19,559			(4,917		)	53,508
Valencia non-controlling interest	(7,231		)	—			—			(7,231		)
Subsidiary preferred stock dividends	(264		)	—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	31,371		$	19,559		$	(4,917	)	$	46,013
At June 30, 2015:
Total Assets	$	4,544,279		$	1,268,862		$	113,877		$	5,927,018
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, 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

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, 2015 and 2014 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	PNM									TNMP		PNMR
	Unrealized									Fair Value
	Gain on			Pension						Adjustment
	Available-for-			Liability						for Cash Flow
	Sale Securities			Adjustment			Total			Hedges		Total
	(In thousands)
Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—	$	(61,755	)
Amounts reclassified from AOCI (pre-tax)	(12,537		)	2,976			(9,561		)	—		(9,561		)
Income tax impact of amounts reclassified	4,913			(1,166		)	3,747			—		3,747
Other OCI changes (pre-tax)	6,157			—			6,157			—		6,157
Income tax impact of other OCI changes	(2,413		)	—			(2,413		)	—		(2,413		)
Net change after income taxes	(3,880		)	1,810			(2,070		)	—		(2,070		)
Balance at June 30, 2015	$	24,128		$	(87,953	)	$	(63,825	)	$	—	$	(63,825	)

Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(57,877	)	$	(263	)	$	(58,140	)
Amounts reclassified from AOCI (pre-tax)	(8,857		)	2,576			(6,281		)	176			(6,105		)
Income tax impact of amounts reclassified	3,488			(1,016		)	2,472			(61		)	2,411
Other OCI changes (pre-tax)	9,855			—			9,855			(153		)	9,702
Income tax impact of other OCI changes	(3,809		)	—			(3,809		)	53			(3,756		)
Net change after income taxes	677			1,560			2,237			15			2,252
Balance at June 30, 2014	$	26,425		$	(82,065	)	$	(55,640	)	$	(248	)	$	(55,888	)

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, 2015 and 2014, approximately 23.0% and 23.0% of the amount reclassified was capitalized into construction work in process and approximately 2.7% and 2.1% was capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes” in the Condensed Consolidated Statements of Earnings.

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)

(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 2014 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, 2015, PNM paid $4.8 million and $9.6 million for fixed charges and $0.5 million and $0.6 million for variable charges. 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. 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,
	2015			2014			2015			2014
	(In thousands)
Operating revenues	$	5,251		$	5,307		$	10,155		$	10,238
Operating expenses	(1,401		)	(1,399		)	(2,924		)	(2,799		)
Earnings attributable to non-controlling interest	$	3,850		$	3,908		$	7,231		$	7,439

Financial Position

	June 30,		December 31,
	2015		2014
	(In thousands)
Current assets	$	3,284	$	2,513
Net property, plant, and equipment	71,180		72,321
Total assets	74,464		74,834
Current liabilities	1,301		1,288
Owners’ equity – non-controlling interest	$	73,163	$	73,546

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)

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)

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 NMPRC and FERC would be required, which could take up to 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. The owner of Valencia subsequently submitted a counter-proposal to PNM in April 2015. PNM is evaluating the terms of the counter-proposal. 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 provided 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 provided PNM with options to renew the leases at fixed rates set forth in the leases for 2 years beyond the termination of the original lease terms. The option periods on certain leases could be further extended for up to an additional 6 years if the appraised remaining useful lives and fair value of the leased assets were greater than parameters set forth in the leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and Note 6 for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities.

PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments. As of June 30, 2015, these 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 $150.5 million, including the renewal terms of the leases that PNM has 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, 2015, PNM could have been required to pay the beneficial owners up to $217.3 million on July 15, 2015 in addition to the regularly scheduled lease payments. In such event, PNM would record the acquired assets at the lower of their fair value or the aggregate of the amount paid and PNM’s carrying value of its investment in PVNGS lessor notes. 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 no assets or liabilities recorded on its Condensed Consolidated Balance Sheets related to the trusts other than accrued lease payments of $18.4 million at June 30, 2015 and $26.0 million at December 31, 2014, which are included in other current liabilities on the Condensed Consolidated Balance Sheets.

PNM has evaluated the PVNGS lease arrangements, including actions taken with respect to renewal and purchase options, 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.

Rio Bravo, formerly known as Delta

PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which was a variable interest under GAAP. PNM controlled the dispatch of the generating plant, which impacted the variable payments made under the PPA and impacted

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)

the economic performance of the entity that owned Delta. This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it was the primary beneficiary of the entity that owned Delta, or to consolidate that entity if it were determined that PNM was the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.

In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owned Delta. PNM closed on the purchase on July 17, 2014 and recorded the purchase as of that date. PNM changed the name of the facility to Rio Bravo.

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. PNM recovered the variable energy charges through its FPPAC. Delta informed PNM that for the three and six months ended June 30, 2014 its revenue was $2.5 million and $4.3 million and its net earnings were $0.3 million and $0.6 million.

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

(6) Lease Commitments

The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS and, through April 1, 2015, an interest in the EIP transmission line. All of the Company’s leases are accounted for as operating leases. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K, including information regarding renewal and purchase options, and actions taken by PNM under the PVNGS leases.

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. The four Unit 1 leases have been extended to expire on January 15, 2023 and one of the Unit 2 leases has been extended to expire on January 15, 2024. For the other three PVNGS Unit 2 leases, PNM elected to purchase the assets underlying those leases on the expiration date of the original leases and has entered into agreements with the lessors that establish the purchase prices, representing the fair market value, to be paid on January 15, 2016 by PNM for the assets underlying the leases. The leases remain in existence and PNM will record the purchases at the termination of the leases on January 15, 2016.

PNM will pay $78.1 million for the assets underlying one of the Unit 2 leases, which is for 31.25 MW of the entitlement from PVNGS Unit 2. PNM will pay $85.2 million for the assets underlying the other two Unit 2 leases, which are for 32.76 MW of the entitlement from PVNGS Unit 2. PNMR Development is also a party to the agreement regarding these two leases, 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, $83.4 million on June 30, 2015, 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, $2.8 million on June 30, 2015, and declines to $1.2 million on January 14, 2016. Currently, PNMR does not anticipate that PNMR Development will exercise the early purchase option.

At March 31, 2015, PNM owned 60% of the EIP and leased the other 40%, under a lease that expired on April 1, 2015. Following procedures set forth in the lease, PNM and the lessor entered into a definitive agreement for PNM to exercise its option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. PNM closed on the purchase on April 1, 2015 and recorded the purchase at that date.

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)

(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 2014 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. During the six months ended June 30, 2015 and the year ended December 31, 2014, 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.

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)

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, 2015			December 31, 2014
PNMR and PNM	(In thousands)
Current assets	$	4,550		$	11,232
	4,550			11,232
Current liabilities	(1,153		)	(1,209		)
Long-term liabilities	—			(477		)
	(1,153		)	(1,686		)
Net	$	3,397		$	9,546

Included in the above table are $1.5 million of current assets at June 30, 2015 and $3.0 million of current assets at December 31, 2014 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, 2015 and December 31, 2014.

At June 30, 2015 and December 31, 2014, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at June 30, 2015 and December 31, 2014, amounts posted as cash collateral under margin arrangements were $1.6 million and $3.8 million for both PNMR and PNM. At June 30, 2015 and December 31, 2014, obligations to return cash collateral were $0.2 million and $0.2 million, for both PNMR and PNM. 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 less than $0.1 million of current assets at June 30, 2015 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. At December 31, 2014, there were no hedges in place under this plan.

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,
	2015			2014			2015			2014
PNMR and PNM	(In thousands)
Electric operating revenues	$	1,003		$	(324	)	$	531		$	(4,475	)
Cost of energy	(99		)	57			(149		)	245
Total gain (loss)	$	904		$	(267	)	$	382		$	(4,230	)

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)

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
PNMR and PNM
June 30, 2015	865,000	(968,305	)
December 31, 2014	650,000	(1,919,000	)

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)
PNMR and PNM
June 30, 2015	$	1,143	$	—	$	83
December 31, 2014	$	1,686	$	—	$	167

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently 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, 2015, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium.  Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales.

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 serving SJGS (Note 11). At June 30, 2015 and December 31, 2014, the fair value of available-for-sale securities included $247.8 million and $244.6 million for the NDT and $5.7 million and $5.5 million for the mine reclamation trust. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

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)

	June 30, 2015				December 31, 2014
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,940	$	—	$	8,276
Equity securities:
Domestic value	15,015		45,750		17,418		45,340
Domestic growth	19,850		78,515		21,354		74,053
International and other	1,147		17,057		156		16,599
Fixed income securities:
U.S. Government	276		30,421		903		22,563
Municipals	3,098		58,986		5,851		68,973
Corporate and other	411		18,881		666		14,341
	$	39,797	$	253,550	$	46,348	$	250,145

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. Gross realized losses shown below exclude the change in realized impairment losses of $(1.2) million and $(0.8) million for the three and six months ended June 30, 2015 and $0.1 million and $0.6 million for the three and six months ended June 30, 2014.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands)
Proceeds from sales	$	62,670		$	30,316		$	94,522		$	53,119
Gross realized gains	$	8,329		$	5,364		$	13,465		$	8,482
Gross realized (losses)	$	(1,578	)	$	(755	)	$	(3,119	)	$	(1,794	)

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 securities impairments considered to be “other than temporary” included in AOCI. All such impairments have been recognized in earnings.

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)

At June 30, 2015, 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	$	4,656	$	17,230	$	17,230
After 1 year through 5 years	21,533		639		—
After 5 years through 10 years	22,577		—		—
After 10 years through 15 years	10,137		—		—
After 15 years through 20 years	10,727		—		—
After 20 years	38,658		—		—
	$	108,288	$	17,869	$	17,230

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. 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 three and six months ended June 30, 2015 and the year ended December 31, 2014.

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.

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)

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, 2015 and December 31, 2014 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, 2015	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,940		$	3,940	$	—
Equity securities:
Domestic value	45,750			45,750		—
Domestic growth	78,515			78,515		—
International and other	17,057			17,057		—
Fixed income securities:
U.S. Government	30,421			29,131		1,290
Municipals	58,986			—		58,986
Corporate and other	18,881			4,119		14,762
	$	253,550		$	178,512	$	75,038
Commodity derivative assets	$	4,550		$	—	$	4,550
Commodity derivative liabilities	(1,153		)	—		(1,153		)
Net	$	3,397		$	—	$	3,397
December 31, 2014
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	8,276		$	8,276	$	—
Equity securities:
Domestic value	45,340			45,340		—
Domestic growth	74,053			74,053		—
International and other	16,599			16,599		—
Fixed income securities:
U.S. Government	22,563			20,808		1,755
Municipals	68,973			—		68,973
Corporate and other	14,341			4,843		9,498
	$	250,145		$	169,919	$	80,226
Commodity derivative assets	$	11,232		$	—	$	11,232
Commodity derivative liabilities	(1,686		)	—		(1,686		)
Net	$	9,546		$	—	$	9,546

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 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, 2015	(In thousands)
PNMR
Long-term debt	$	2,031,158	$	2,205,847	$	—	$	2,205,847	$	—
Investment in PVNGS lessor notes	$	16,568	$	17,230	$	—	$	—	$	17,230
Other investments	$	507	$	1,146	$	507	$	—	$	639
PNM
Long-term debt	$	1,515,676	$	1,644,887	$	—	$	1,644,887	$	—
Investment in PVNGS lessor notes	$	16,568	$	17,230	$	—	$	—	$	17,230
Other investments	$	265	$	265	$	265	$	—	$	—
TNMP
Long-term debt	$	365,482	$	410,961	$	—	$	410,961	$	—
Other investments	$	242	$	242	$	242	$	—	$	—
December 31, 2014
PNMR
Long-term debt	$	1,975,090	$	2,173,117	$	—	$	2,173,117	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	1,762	$	2,375	$	639	$	—	$	1,736
PNM
Long-term debt	$	1,490,657	$	1,624,222	$	—	$	1,624,222	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	397	$	397	$	397	$	—	$	—
TNMP
Long-term debt	$	365,667	$	427,356	$	—	$	427,356	$	—
Other investments	$	242	$	242	$	242	$	—	$	—

(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”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. 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. 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 2014 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 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, 2015 and December 31, 2014, PNMR had unrecognized expense related to stock awards of $7.8 million and $6.5 million. 

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 grant date fair value for other restricted stock awards 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 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	2015			2014
Expected quarterly dividends per share	$	0.200		$	0.185
Risk-free interest rate	0.92		%	0.62		%
Market-Based Shares
Dividend yield	2.87		%	2.82		%
Expected volatility	18.73		%	25.11		%
Risk-free interest rate	1.00		%	0.64		%

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, 2015:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2014	258,770		$	22.31	920,505		$	20.39
Granted	340,020		$	20.34	—		$	—
Exercised	(348,095	)	$	18.59	(210,945	)	$	20.07
Forfeited	—		$	—	(1,000	)	$	30.50
Expired	—		$	—	(66,201	)	$	27.90
Outstanding at June 30, 2015	250,695		$	24.82	642,359		$	19.51

PNMR’s stock-based compensation program provides for performance and market targets through 2017. Included as granted and exercised in the above table are 179,845 previously awarded shares that were earned for the 2012 through 2014 performance measurement period and approved by the Board in February 2015 (based upon achieving market targets at “target” levels, weighted at 60%, and performance targets at “maximum” levels, weighted at 40%). Excluded from the above table, are maximums of 180,970, 165,628, and 168,258 shares for the three-year performance periods ending in 2015, 2016, and 2017 that would be awarded if all performance and market criteria are achieved at maximum levels 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 PNMR meets specific market targets at the end of 2016 and she remains an employee of the Company. Under the agreement, she would receive 35,000 of the total shares if

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)

PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2014 and the Board approved her receiving the 35,000 shares in February 2015, which shares are included as granted and exercised in the above table. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2016, he would receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. If the target for the first performance period is not met, but the target for the second performance period is met, he would receive both awards, less any amount received previously under the agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include any restricted stock shares under this retention award agreement.

In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she would receive 17,953 of the total shares if PNMR achieves specific performance targets at the end of 2017. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include any restricted stock shares under this retention award agreement.

At June 30, 2015, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $4.7 million with a weighted-average remaining contract life of 2.62 years. At June 30, 2015, the exercise price of 245,950 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,
Restricted Stock	2015		2014
Weighted-average grant date fair value	$	20.34	$	21.27
Total fair value of restricted shares that vested (in thousands)	$	6,470	$	4,854
Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	—
Total intrinsic value of options exercised (in thousands)	$	1,759	$	1,779

(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 2014 Annual Reports on Form 10-K.

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)

Financing Activities

On March 5, 2014, PNM entered into a $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 2013 Term Loan Agreement and other short-term amounts outstanding. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.14% at June 30, 2015, must be repaid on or before September 4, 2015, and is reflected in current maturities of long-term debt on the Condensed Consolidated Balance Sheets. The PNM 2014 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNM 2014 Term Loan Agreement has a cross default provision and a change of control provision.

On December 22, 2014, PNM entered into a multi-draw term loan facility (the “PNM Multi-draw Term Loan”) with JPMorgan Chase Bank, N.A., as Lender and Administrative Agent. The $125.0 million facility has a maturity date of June 21, 2016. At December 31, 2014, outstanding borrowings under the PNM Multi-draw Term Loan were $100.0 million. PNM drew the remaining capacity of $25.0 million on May 8, 2015 resulting in outstanding borrowings at June 30, 2015 of $125.0 million, which are included in current maturities of long-term debt on the Condensed Consolidated Balance Sheet. The PNM Multi-draw Term Loan bears interest at a variable rate, which was 0.77% at June 30, 2015. The PNM Multi-draw Term Loan includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Multi-draw Term Loan Agreement has a cross default provision and a change of control provision.

On March 9, 2015, PNMR entered into a $150.0 million Term Loan Agreement (“PNMR 2015 Term Loan Agreement”) between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and Administrative Agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate, which was 1.19% at June 30, 2015, and must be repaid on or before March 9, 2018. The PNMR 2015 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNMR 2015 Term Loan Agreement has a cross default provision and a change of control provision.

At December 31, 2014, PNMR had an aggregate outstanding principal amount of $118.8 million of its 9.25% Senior Unsecured Notes, Series A, which were due on May 15, 2015. PNMR repaid all of the 9.25% Senior Unsecured Notes, Series A at the scheduled maturity, utilizing proceeds from the PNMR 2015 Term Loan Agreement and borrowings under the PNMR Revolving Credit Facility.

At December 31, 2014, PNM had a $39.3 million series of outstanding Senior Unsecured Notes, Pollution Control Revenue Bonds, which have a final maturity of June 1, 2043. The PCRBs were subject to mandatory tender for remarketing on June 1, 2015 and were successfully remarketed on that date. The notes now bear interest at 2.40%, continue to have an outstanding amount of $39.3 million, and are subject to mandatory tender for remarketing on June 1, 2020.

Short-term Debt

The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. Both of these facilities mature on October 31, 2019 and provide for an additional one-year extension option, subject to approval by a majority of the lenders. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. The TNMP Revolving Credit Facility 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, 2015, TNMP had $4.1 million in borrowings from PNMR under its intercompany loan agreement. At June 30, 2015, the weighted average interest rate was 1.69% for the PNMR Revolving Credit Facility, 1.44% for the PNM Revolving Credit Facility, 1.44% for the PNM New Mexico Credit Facility, 1.19% for the TNMP Revolving Credit Facility, and 1.04% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2015. Short-term debt outstanding consisted of:

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)

	June 30,		December 31,
Short-term Debt	2015		2014
	(In thousands)
PNM:
Revolving credit facility	$	31,100	$	—
PNM New Mexico Credit Facility	20,000		—
TNMP – Revolving credit facility	29,000		5,000
PNMR:
Revolving credit facility	7,500		600
PNMR Term Loan Agreement	100,000		100,000
	$	187,600	$	105,600

At July 24, 2015, PNMR, PNM, and TNMP had $293.2 million, $353.6 million, and $42.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $30.0 million of availability under the PNM New Mexico Credit Facility. Total availability at July 24, 2015, on a consolidated basis, was $719.7 million for PNMR. As of July 24, 2015, PNM had $18.7 million and TNMP had $13.2 million in borrowings from PNMR under their intercompany loan agreements. At July 24, 2015, 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 (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans.

Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year.

45

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM Plans

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

	Three Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	51		$	45		$	—	$	—
Interest cost	7,064			7,541			1,023			1,159			190		205
Expected return on plan assets	(9,831		)	(9,511		)	(1,403		)	(1,410		)	—		—
Amortization of net (gain) loss	3,705			3,255			491			556			81		52
Amortization of prior service cost	(241		)	(241		)	(160		)	(336		)	—		—
Net periodic benefit cost	$	697		$	1,044		$	2		$	14		$	271	$	257
	Six Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	102		$	91		$	—	$	—
Interest cost	14,127			15,082			2,045			2,315			380		411
Expected return on plan assets	(19,662		)	(19,022		)	(2,805		)	(2,819		)	—		—
Amortization of net (gain) loss	7,410			6,510			983			1,113			162		105
Amortization of prior service cost	(483		)	(483		)	(321		)	(672		)	—		—
Net periodic benefit cost	$	1,392		$	2,087		$	4		$	28		$	542	$	516

PNM made contributions to its pension plan trust of zero and $30.0 million in the three and six months ended June 30, 2015 and made no contributions in the three and six months ended June 30, 2014. PNM does not anticipate making additional contributions to its pension trust in 2015.  Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the PNM pension plan trust for 2016-2019 are estimated to total $22.0 million. These anticipated contributions were developed using current funding assumptions, with discount rates of 4.8% 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, 2015 and $0.8 million and $1.6 million in the three and six months ended June 30, 2014. PNM expects to make contributions to the OPEB trust totaling $3.5 million in 2015 and $14.0 million for 2016-2019.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $0.9 million in the three and six months ended June 30, 2015 and $0.4 million and $0.7 million in the three and six months ended June 30, 2014 and are expected to total $1.5 million during 2015.

46

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	62		$	59		$	—	$	—
Interest cost	761			798			152			155			9		10
Expected return on plan assets	(1,105		)	(1,132		)	(130		)	(133		)	—		—
Amortization of net (gain) loss	195			166			—			(31		)	1		—
Amortization of prior service cost	—			—			—			8			—		—
Net Periodic Benefit Cost (Income)	$	(149	)	$	(168	)	$	84		$	58		$	10	$	10
	Six Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	124		$	119		$	—	$	—
Interest cost	1,521			1,597			304			309			18		20
Expected return on plan assets	(2,210		)	(2,263		)	(260		)	(267		)	—		—
Amortization of net (gain) loss	391			333			—			(61		)	2		—
Amortization of prior service cost	—			—			—			16			—		—
Net Periodic Benefit Cost (Income)	$	(298	)	$	(333	)	$	168		$	116		$	20	$	20

TNMP made no contribution to its pension trust in 2014 and does not anticipate making any contributions in 2015-2019 based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. These expectations were developed using current funding assumptions, including discount rates of 4.8% 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 no contributions to the OPEB trust in the three and six months ended June 30, 2015 and $0.3 million in the three and six months ended June 30, 2014. TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2015 and $1.4 million for 2016-2019. 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, 2015 and 2014 and are expected to total $0.1 million during 2015.

47

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(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 periodically 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 any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2014 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 alleged that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, and on October 7, 2014, APS received a settlement payment of $57.4 million for costs paid through June 30, 2011, for DOE’s failure to accept spent nuclear fuel generated at PVNGS. PNM’s share of the settlement was $5.9 million, substantially all of which was credited back to PNM’s customers. The settlement agreement also establishes a process for the payment of subsequent claims through December 31, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. On October 31, 2014, APS submitted a claim for costs paid between July 1, 2011 and June 30, 2014 and agreed to a settlement amount of $42.0 million in March 2015. PNM’s share of the settlement, which amounted to $4.3 million, including $3.1 million credited back to PNM’s customers, was recorded in the three months ended March 31, 2015. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a

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)

component of fuel expense as the fuel is consumed. At June 30, 2015 and December 31, 2014, PNM had a liability for interim storage costs of $12.5 million and $12.3 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 and temporary storage rule (the “Waste Confidence Decision”). The D.C. Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’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 Waste Confidence Decision update for further action consistent with NEPA. On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision. The NRC commissioners also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.

In September 2013, the NRC issued its draft generic EIS to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel.  The continued storage rule adopted the findings of the generic EIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although PVNGS had not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. PNM is unable to predict the outcome of this matter.

PVNGS has sufficient capacity at its on-site ISFSI to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027.  Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047.  If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of DOE’s intention to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of its 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

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)

visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.

SJGS

BART Determination Process –SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that required installation of selective catalytic reduction technology (“SCR”) on all four units by September 21, 2016. In November 2012, EPA approved all components of the SIP, except for the NOx BART determination for SJGS, which continued to be subject to the FIP.

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

During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised 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.

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013 and NMED developed a RSIP, both of which reflect the terms of the non-binding agreement. The EIB approved the RSIP in September 2013 and it was submitted to EPA for approval in October 2013. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and became effective on November 10, 2014.

Conversion of SJGS Units 1 and 4 to balanced draft technology (“BDT”) is included with the installation of SNCRs in the RSIP. The requirement to install BDT was made binding and enforceable in the NSR permit that accompanied the RSIP submitted to the EPA. EPA’s rule approving the RSIP specifically references the NSR permit by including a condition that requires “modification of the fan systems on Units 1 and 4 to achieve ‘balanced’ draft configuration ….”

Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM took steps to commence installation of SCRs at SJGS. In October 2012, PNM entered into a contract with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million. The costs for the project to install SCRs would encompass installation of BDT equipment to comply with the NAAQS requirements described below. The construction contract was terminated in December 2014 following approval of the RSIP by EPA.

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 BDT equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS.

The above estimates include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM’s share of the costs described above would have been about 46.3%.

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

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)

PNM entered into a contract for management of the construction and in September 2014 entered into a construction and procurement contract. Installation of SNCRs and BDT on SJGS Unit 1 was completed in April 2015 and PNM anticipates that installation of SNCRs and BDT on Unit 4 can be completed within the timeframe contained in the RSIP.

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

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

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

• An order allowing cost recovery for PNM’s share of the installation of SNCR and BDT 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 have been a reduction of 340 MW in PNM’s ownership of SJGS

The December 20, 2013 NMPRC filing identified a new 177 MW natural gas-fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 12. On June 30, 2015, PNM filed an application for a CCN for the gas facility, which is currently contemplated to be rated at 187 MW, to be located at SJGS. PNM estimates the cost of these identified resources would be approximately $212.5 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs would be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of SNCR and BDT equipment.

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 regarding ownership restructuring and other matters (see SJGS Ownership Restructuring Matters below). In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements were memorialized in the resolution and term sheet described below.

On October 1, 2014, PNM, the staff of the NMPRC, the NMAG, New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico filed a stipulation with the NMPRC. NMIEC subsequently joined the agreement. New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico have since withdrawn support of the stipulation. Statements of opposition were filed by other intervenors.

Under the terms of the stipulation, PNM:

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

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

• Would recover 50% of the estimated $231 million undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a twenty year period and would include a return on the unrecovered amount at PNM’s WACC; at June 30, 2015, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $278 million

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)

• Would be granted a CCN for 134 MW of PVNGS Unit 3 at a January 1, 2018 value of $221.1 million ($1,650 per KW); PNM’s ownership share of PVNGS would also be subject to a capacity factor performance threshold of 75% for a seven year period beginning January 1, 2018; subject to certain exceptions, if the capacity factor is not achieved in any year, PNM would refund the cost of replacement power through its FPPAC; at June 30, 2015, PNM’s net book value of PVNGS Unit 3 was approximately $147 million

• Would file for recovery of its reasonable and prudent costs of installation of the SNCR and BDT equipment requirements at SJGS Units 1 and 4 up to $90.6 million

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

A public hearing in the NMPRC case was held in January 2015. In connection with the hearing, PNM filed testimony indicating that:

• PNM would not acquire the 65 MW of capacity in SJGS Unit 4 that was no longer anticipated to be acquired by the City of Farmington, as discussed under SJGS Ownership Restructuring Matters below

• PNM would not enter into a coal supply agreement for SJGS that extends beyond 2022 without NMPRC approval

• PNM would have an ownership restructuring agreement for SJGS in place by May 1, 2015

If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. Although PNM would record the regulatory disallowance upon approval by the NMPRC and satisfaction of any material conditions precedent, the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order, as well as PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3 and PVNGS Unit 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values of the plants. Based on the provisions of the stipulation as filed and PNM’s current projection of December 31, 2017 book values, PNM estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.

On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommends that the NMPRC reject the stipulation as proposed. The certification recommends that the abandonment of SJGS Units 2 and 3 be conditionally approved subject to PNM proposing adequate replacement capacity, approval of the CCN for PVNGS Unit 3 at its net book value on December 31, 2017, approval of recovery of an estimated $128.5 million, representing 50% of the remaining undepreciated investment in SJGS Units 2 and 3 at December 31, 2017, and denial of the CCN for the additional 132 MW of Unit 4 of SJGS. The certification states that PNM may re-apply for a CCN for the 132 MW after it has presented final restructuring and post-2017 coal supply agreements for SJGS. On April 20, 2015, PNM filed exceptions to the certification. PNM argued that the proposed modifications to the stipulation do not balance customer and shareholder interests, upset the balance contained in the stipulation, that the schedule recommended by the Hearing Examiner for PNM to file a replacement plan would effectively preclude the inclusion of the 132 MW of additional SJGS Unit 4 capacity in the replacement plan thereby jeopardizing the restructuring agreement and the continued operation of SJGS to the detriment of customers, and that the Hearing Examiner erred in recommending a lower rate base value for PNM’s share of PVNGS Unit 3. If the NMPRC issues an order that modifies the stipulation, any stipulating party can void the stipulation. The certification recommends that the parties be given seven days to decide whether to accept any modifications after the NMPRC issues an order. The NMPRC can approve, reject, or modify the certification. If the NMPRC were to issue an order adopting all of the modifications to the stipulation recommended by the Hearing Examiner, PNM estimates the net pre-tax regulatory disallowance referenced above would become an amount between $145 million and $155 million.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of confidential, substantially final, unexecuted restructuring, coal supply, and related agreements for SJGS. See SJGS Ownership Restructuring Matters and Coal Supply below. On May 27, 2015, the NMPRC issued an order requiring PNM to file executed restructuring and coal supply agreements by July 1, 2015. The order provided that PNM could request an extension of the required filing date to August 1, 2015 if such request was based on specific and verifiable facts. PNM subsequently requested an extension, citing that certain of the owners of SJGS were

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governmental entities and required the additional time in order to meet statutory public notice and meeting requirements. The NMPRC granted PNM an extension to August 1, 2015 to file the executed restructuring agreement. On July 1, 2015, PNM filed the executed coal supply and related agreements described under Coal Supply below with the NMPRC. On July 1, 2015, PNM also filed partially executed agreements related to restructuring discussed under SJGS Ownership Restructuring Matters below. On July 31, 2015, PNM filed fully executed restructuring agreements, along with testimony supporting the agreements and a CCN for the 132 MW of additional SJGS Unit 4 capacity.

In June 2015, a NMPRC Commissioner issued an order designating a facilitator to determine whether an uncontested settlement among some or all of the parties in this case could be accomplished. A mediation process is on-going. A public hearing on PNM’s application concerning BART for SJGS is scheduled to begin on September 30, 2015. Although PNM expects a decision from the NMPRC in the fourth quarter of 2015, PNM is unable to predict what action the NMPRC will take, whether any party will void the stipulation, or the ultimate outcome of this matter.

SJGS Ownership Restructuring Matters – As discussed in the 2014 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 currently effective contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. The California participants have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4.

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

On June 26, 2014, a non-binding resolution (the “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 Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCR and BDT equipment, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating 58.7%. On September 2, 2014, the SJGS Coordination Committee adopted a non-binding supplement to the Resolution, which provides for allocation of future costs of decommissioning among current SJGS owners using a time-based sliding scale and outlines indemnification obligations. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants would need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, on July 1, 2015, PNM entered into an agreement for the supply of coal to SJGS through June 30, 2022.

In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the Resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. PNM filed the Fuel and

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Capital Funding Agreement with FERC on September 18, 2014, with a request for a retroactive effective date to July 1, 2014. FERC approved the request on November 13, 2014.

On January 7, 2015, the City of Farmington, New Mexico, which has an ownership interest in Unit 4, notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs in that unit unsubscribed. As discussed under NMPRC Filing above, PNM has indicated that it will not acquire any of the unsubscribed MWs. However, PNMR currently anticipates that PNMR Development would acquire the 65 MWs. The City of Farmington’s action was taken under the Fuel and Capital Funding Agreement and has the impact of negating certain provisions of that agreement, including the payment arrangement related to SNCRs and PNM’s acquisition of the exiting participants’ coal inventory described above, and reinstating the voting and capital improvement cost allocations under the current SJPPA. Accordingly, on February 3, 2015, PNM informed the participants in the Fuel and Capital Funding Agreement that the agreement would terminate by its terms no later than February 6, 2015. The City of Farmington and the other continuing participants in SJGS have indicated that they remain committed to on-going ownership in SJGS.

On May 19, 2015, PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 entered into a Capacity Option and Funding Agreement (“COFA”), which provides PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. PNMR’s current projection of capital expenditures includes those of PNMR Development for the 65 MW. PNMR guarantees the obligations of PNMR Development under the COFA. The COFA will terminate on the earliest of January 1, 2016, the effective date of a SJGS restructuring agreement, the date PNM notifies the other parties that it has failed to receive required regulatory approvals for the SJGS restructuring, the date any California owner opposes PNM’s application before the NMPRC, or the date PNM elects to terminate because another SJGS owner has given notice that it will no longer participate in the restructuring process. If the COFA is terminated, the California owners would not be obligated to repay amounts funded by PNM and PNMR Development. On June 23, 2015, ABCWUA filed a motion with the NMPRC to void the COFA alleging that the COFA violated the NMPRC’s rules regarding affiliate transactions.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of a confidential, substantially final, unexecuted copy of the San Juan Project Restructuring Agreement (“RA”). The RA sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the Resolution. PNMR Development would also be a party to the RA and would acquire an ownership interest in SJGS Unit 4 when the California owners exit, but would have obligations related to Unit 4 before then. On December 31, 2017, PNM would acquire 132 MW of the capacity in SJGS Unit 4 from the California owners and PNMR Development would acquire 65 MW of such capacity, as contemplated by the COFA. The RA is dependent on and would become effective upon the last of the approval by NMPRC, the approval by FERC, the approval of each participant’s board or other decision-making body, and the effective date of a new coal supply agreement for SJGS. It is currently anticipated that the new coal supply agreement and the RA would become effective contemporaneously on January 1, 2016. The RA sets forth the terms under which PNM would acquire the coal inventory of the exiting SJGS participants on January 1, 2016 and provide coal supply to the exiting participants during the period from January 1, 2016 through December 31, 2017, which arrangement PNM believes will provide economic benefits that will be passed on to PNM’s customers. The RA also includes provisions whereby the exiting owners will make payments to certain of the remaining participants, not including PNM, related to the restructuring. PNM’s notice also included submittal of confidential, substantially final, unexecuted copies of documents related to coal supply for SJGS beginning January 1, 2016 (see “Coal Supply” below). On July 1, 2015, PNM filed with the NMPRC fully executed coal supply and related agreements along with a partially executed RA, an agreement covering decommissioning obligations and funding for the SJGS plant, and related amendments to the SJPPA. PNM filed fully executed RA and related agreements along with supporting testimony on July 31, 2015.

PNM is unable to predict whether all required approvals will be obtained and other conditions satisfied in order for the agreements discussed above to become effective and restructuring to be consummated.

Other SJGS Matters – 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 BDT requirements described above, to the SJGS participants in Unit 1 and Unit 4 for

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approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. In addition, other capital projects related to Unit 4 were not approved by the participants. PNM subsequently requested that the owners of Unit 4 approve the expenditure of costs critical to being able to comply with the time frame in the RSIP with respect to the Unit 4 project of $1.9 million on March 10, 2014, $6.4 million on June 27, 2014, and total project expenses of $76.6 million (including the two prior requests) on January 22, 2015. The Unit 4 owners did not approve these requests.

PNM, in its capacity as operating agent of SJGS, is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM must evaluate its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and take reasonable and prudent actions as it deems necessary. Therefore, on March 10, 2014, July 14, 2014, and March 20, 2015, PNM, as operating agent for SJGS, issued “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.

As discussed above, EPA approved the RSIP and withdrew the FIP on October 9, 2014 and those approvals became effective on November 10, 2014. PNM believes significant progress is being made towards implementation of the RSIP. However, the final implementation of the RSIP is still dependent upon PNM obtaining NMPRC approval to retire San Juan Units 2 and 3 and the agreements for restructuring and a new coal supply becoming effective. PNM can provide no assurance that these requirements will be accomplished. If the RSIP requirements ultimately are not implemented due to adverse or alternative regulatory, legislative, legal, or restructuring developments or other factors, PNM would need to pursue other alternatives to address compliance with the CAA.Failure to implement the RSIP or an agreed to alternative could jeopardize the economic viability of SJGS. PNM will seek recovery from its ratepayers for costs that may be incurred as a result of the CAA requirements. PNM is unable to predict the ultimate outcome of these matters.

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

Four Corners

On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to permanently close 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 shut down 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.

On December 30, 2013, APS announced the closing of its purchase of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. Concurrently with the closing of the SCE transaction, the ownership of the coal supplier and operator of the mine that serves Four Corners was transferred to a company formed by the Navajo Nation to own the mine and develop other energy projects. Also occurring concurrently, the Four Corners co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031.

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 was undertaken 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 EIS was finalized on May 1, 2015. On July 17, 2015, DOI issued a Record of Decision, which approves the 25-year site lease extension with the

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Navajo Nation for Four Corners, authorizes continued mining operations to supply the remaining units at Four Corners, renews transmission line and access road rights-of-way on the Navajo and Hopi Reservations, and accepts the proposed mining plan for the Navajo Mine. The record of decision provides the authority for the Bureau of Indian Affairs to sign the lease amendments and rights-of-way renewals, which are anticipated to occur in the near future.  In addition, installation of SCR control technology at Four Corners requires a PSD permit, which APS received in December 2014.

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 $91.8 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.

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.  On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposes deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO₂ emissions. The settlement results from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree requires the following: 1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO₂ in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; 2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule.  SJGS and Four Corners SO₂ emissions are below the tonnages set forth in 1) above. EPA regions sent out letters to state environmental agencies explaining how EPA plans to implement the consent decree.  The letters outline the schedule that EPA expects states to follow in moving forward with new SO₂ non-attainment designations. NMED did not receive a letter.

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 NSR air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. The revised permit requires the reduction of SO₂ emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and continues to require the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO₂, and particulate matter. These reductions will help SJGS meet the NAAQS. The BDT equipment modifications are to 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. 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 60-70 parts per billion (“ppb”). On December 17, 2014, EPA published a proposed rule that would revise the NAAQS for ground level ozone. The rule would reduce the current primary 8-hour ozone NAAQS from 75 ppb to between 70 and 65 ppb. EPA is

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proposing a secondary standard to provide protection against cumulative exposures that can damage plants and trees. To achieve this level of protection, EPA is proposing to set an 8-hour secondary standard at a level within the range of 65 to 70 ppb. According to EPA, 2011-2013 ozone ambient air monitoring data indicates that Bernalillo, Dona Ana, Eddy, and San Juan counties in New Mexico exceed a 70 ppb ozone concentration. In addition, Lea, Luna, Santa Fe, and Valencia counties exceed the 65 ppb ozone concentration. Counties that exceed the ozone NAAQS would be designated as nonattainment for ozone. NMED would have responsibility for bringing those counties 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 controls to meet a new ozone NAAQS. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional controls would be required at any of its affected facilities as a result of ozone non-attainment designation. EPA is under a court order to finalize the ozone standard by October 1, 2015.

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 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties’ dispute is deemed settled.

In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM’s mercury controls. NMED and plaintiffs sought to require PNM to implement additional mercury controls. PNM estimated the implementation would increase annual mercury control costs for the entire station, which are currently $0.7 million, to a total of $6.6 million. On March 23, 2014, the court entered a stipulated order reflecting an agreement reached by the parties. Under the stipulated order, PNM was required to repeat the mercury study required under the Consent Decree using sorbent traps instead of the continuous emissions monitoring system used in the initial study. The results of the mercury study would establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM completed stack testing and submitted the study report to NMED and the plaintiffs in December 2014. Based on PNM’s cost/benefit analysis, PNM recommended that the carbon injection not be increased from its current level. On March 18, 2015, NMED and the plaintiffs approved PNM’s recommendation for the activated carbon injection rate. The NSR permit issued by NMED on May 14, 2015 incorporates this operational parameter as a permit condition.

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 parties have agreed on terms of a settlement. The terms of the settlement do not have a material impact on PNM.  On June 24, 2015, the United States Department of Justice (“DOJ”) lodged the executed consent decree with the United States District Court for the District of New Mexico. On that same day, DOJ also published notice of the filing in the Federal Register, which opened a 30-day period for public comment. The settlement would resolve claims by the government and environmental plaintiffs that the co-owners violated the CAA by modifying Four Corners Units 4 and 5 without first obtaining a pre-construction permit from EPA. The settlement would require installation of pollution control technology and implementation of other measures to reduce SO₂ and NOx emissions from the two units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule BART requirements. The settlement would also require Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.2 million for certain environmental mitigation projects to benefit the Navajo Nation. PNM would be responsible for 13% of these costs based on its ownership interest in the units at the

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time of the alleged violations, which PNM recorded in 2014. At the end of the 30-day comment period, the United States will file a motion with the Court to advise the court of any comments received and of the United States’ position as to whether the proposed decree should be approved and entered by the court.

Four Corners Coal Mine

In 2012, several environmental groups filed a lawsuit in federal district court against the OSM challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners (“Area IV North”). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes action to cure the defect in its permitting process identified by the court. APS has indicated that the owner of the mine does not anticipate any near-term interruption of coal supply to the plant as a result of the suspension of mining in Area IV North. PNM cannot predict the time period that will be required for OSM’s further permitting process to be completed or whether the outcome of the process will be sufficient to allow the permit to be reinstated.

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 NEPA violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents.  WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. Legal briefing is complete. The matter has been stayed until August 21, 2015 by the court so that the parties can engage in settlement negotiations. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and SJGS. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation’s authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the 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 signed its final cooling water intake structures rule on May 16, 2014, which establishes national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The final rule was published on August 15, 2014 and became effective October 14, 2014.

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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 (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and 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. The renewal date for the SJGS National Pollutant Discharge Elimination System (“NPDES”) permit is March 31, 2016; however, additional time to submit the application may be allowed by the NPDES permit writer. Because of the discretion afforded to EPA with respect to entrainment requirements, PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. However, the costs are not expected to be material. APS is currently in discussions with EPA Region 9, the NPDES 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. 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 PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM’s obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced similar results. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well

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(Unaudited)

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

Coal Combustion Byproducts Waste Disposal

CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners.  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 included two options for waste designation of coal ash. One option was 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 was 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 is developing a proposed rule governing the placement of CCBs at coal mining and reclamation operations. 

On January 29, 2014, in a consolidated case in the D.C. Circuit involving several environmental groups, including Sierra Club, and industry group members, the court issued 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.

On December 19, 2014, EPA issued its coal ash rule, including a non-hazardous waste determination for coal ash. Coal ash will be regulated as a solid waste under Subtitle D of RCRA. The rule does not cover mine placement of coal ash and OSM is expected to publish a rule covering mine placement in 2015. It is expected that OSM will be influenced by EPA’s rule. Because the rule is promulgated under Subtitle D, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non-compliance with the new requirements. EPA published the final CCB rule in the Federal Register on April 17, 2015. PNM is continuing to review the rule to fully understand its implications, but does not expect it to have a material impact on PNM’s operations, financial position, or cash flows.

The rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCB rules. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s 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 were required to comply with the MATS rule by April 16, 2015, unless the facility was granted a 1-year extension under CAA section 112(i)(3). PNM has control technology on each of the four units at SJGS that provides 99% mercury removal efficiency. The plant is in compliance with the MATS and no changes at SJGS are anticipated as a result of the Supreme Court action. Therefore, PNM did not request an extension and began complying with the MATS rule by the date specified in the rule. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule. 

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(Unaudited)

On June 29, 2015, the United States Supreme Court issued its decision overturning the MATS rule. The justices ruled that EPA should have taken costs to utilities and others in the power sector into consideration before issuing the MATS rule. The case is now remanded to the D.C. Circuit for further proceedings consistent with the opinion.

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are currently 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, 2015 and December 31, 2014, prepayments for coal, which are included in other current assets, amounted to $41.9 million and $37.3 million. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement (“UG-CSA”) to supply processed coal for operation of SJGS through 2017. The parties to the UG-CSA are SJCC, PNM, and Tucson. Under the UG-CSA, 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 UG-CSA. The UG-CSA contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS after the expiration of the current coal sales agreement. As discussed under SJGS Ownership Restructuring Matters above, the Resolution and the non-binding term sheet approved by the SJGS Coordination Committee on June 26, 2014 recognize that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants would need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017. The remaining participants began the process of negotiating agreements concerning future fuel supply for SJGS. On October 1, 2014, the San Juan Fuels Committee approved a resolution authorizing an amendment to the UG-CSA. The amendment provided for the negotiation of a potential purchase transaction for the mine assets by one or more of the utilities, an affiliate, or another entity agreed to by the parties to be consummated on or before December 31, 2016. The amendment, which was effective as of October 2, 2014, also released the parties from the obligation to negotiate an extension of the UG-CSA, but does not impact the utilities’ option to purchase the mining assets at the end of the current contract term if the purchase transaction is not completed.

Following extensive negotiations among the SJGS participants, the owner of SJCC, and third-party miners, substantially final, unexecuted forms of agreements were negotiated under which the ownership of SJCC would transfer to a new third-party miner and PNM would enter into a new Coal Supply Agreement (“CSA”) and agreements for CCB disposal and mine reclamation services with SJCC on or about January 1, 2016. On May 1, 2015, PNM filed a notice of submittal of confidential, substantially final, unexecuted copies of the CSA, the mine reclamation agreement, and the CCB disposal agreement with the NMPRC. Effectiveness of the agreements would be dependent upon the closing of the purchase of SJCC by the new third-party miner and the finalization of the RA and other agreements, which along with regulatory approvals are necessary for the restructuring of ownership in SJGS to be consummated. On May 14, 2015, PNM and Westmoreland Coal Company (“Westmoreland”) entered into a letter agreement whereby each party agreed to enter into and deliver the CSA, the mine reclamation agreement, and the CCB disposal agreement on terms substantially in the form submitted to the NMPRC on May 1, 2015.

The NMPRC issued an order on May 27, 2015 requiring that PNM file executed agreements related to coal supply by July 1, 2015. On July 1, 2015, PNM and Westmoreland entered into the CSA, pursuant to which Westmoreland would supply all of the coal requirements of SJGS through June 30, 2022, under substantially the same terms as were contemplated by the unexecuted CSA with SJCC filed with the NMPRC on May 1, 2015. PNM and Westmoreland also entered into agreements under which Westmoreland will provide CCB disposal and mine reclamation services. Contemporaneous with the entry into the coal-related agreements, Westmoreland entered into a stock purchase agreement on July 1, 2015 that provides that Westmoreland will acquire all of the capital stock of SJCC. Upon closing under the stock purchase agreement, Westmoreland’s rights and obligations under the CSA and the agreements for CCB disposal and mine reclamation services will be assigned to SJCC. PNM and Westmoreland also entered into an agreement to terminate the May 14, 2015 letter agreement. In addition, PNM, TEP, SJCC, and SJCC’s owner

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(Unaudited)

entered into an agreement to terminate the existing UG-CSA upon the effective date of the new CSA. The CSA and related agreements will become effective upon the closing of that stock purchase agreement and the effectiveness of the RA. If the CSA does not become effective, the UG-CSA would remain in effect through its contractual expiration on December 31, 2017. The CSA and related agreements were filed with the NMPRC on July 1, 2015.

Pricing under the CSA would primarily be fixed, adjusted to reflect general inflation. The pricing structure takes into account that SJCC has been paid for coal mined but not delivered, as discussed above. PNM would have the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. The RA sets forth terms under which PNM will supply coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and to the SJGS remaining participants over the term of the CSA. PNM anticipates that coal costs under the CSA will be significantly less than under the current arrangement with SJCC. Since substantially all coal costs are passed through PNM’s FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners, which is discussed above, would be passed through to PNM’s customers.

It is currently anticipated that the CSA and the RA would become effective contemporaneously on January 1, 2016. PNM cannot predict if all of the necessary requirements will be satisfied and all approvals obtained in order for these agreements to become effective.

Four Corners

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, beginning in July 2016 and 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 30% at the inception of the new contract. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

Coal Mine Reclamation

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 current 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 2014 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $56.5 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, 2015. At June 30, 2015 and December 31, 2014, liabilities, in current dollars, of $25.4 million and $25.7 million for surface mine reclamation and $9.1 million and $8.6 million for underground mine reclamation were recorded in other deferred credits. On June 1, 2012, the SJGS owners entered into a trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the UG-CSA. As part of the restructuring of SJGS ownership (See SJGS Ownership Restructuring Matters above), SJGS owners and PNMR Development have negotiated the terms of an amended agreement to provide funding to compensate SJCC for post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable trust, and periodically deposit funding into the trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. PNM funded $1.0 million in 2014, $0.3 million in 2013, and $3.5 million in 2012. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels for 2015 and 2016. PNM anticipates funding approximately $4.0 million in 2015 and $5.0 million in 2016 based on the interim funding requirements.

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

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(Unaudited)

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, which was performed in 2013, 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. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. Regulatory determinations made by the NMPRC may also affect the impact on PNM. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

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 although the BLM has indicated that final action on the proposed rule is scheduled for October 2015.

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.

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 9.4%, 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. NMTRD denied the refund claim. 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. On June 30, 2015, the court ruled that the assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. NMTRD has indicated it intends to appeal the decision. PNM cannot predict the timing or outcome of this litigation. However, PNM does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.

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 $13.4 billion per occurrence. Commercial insurance carriers provide $375 million and $13.0 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.

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(Unaudited)

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 $5.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions.

Water Supply

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

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

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

PVNGS Water Supply Litigation

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

San Juan River Adjudication

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

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

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(Unaudited)

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. The court denied the utilities’ motion for judgment. The court further granted the County’s motion to dismiss the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. In subsequent briefing in federal court, the County filed a motion for judgment on one of the utilities’ claims, which was granted by the court, leaving a claim regarding telecommunications service as the remaining federal claim. This matter is ongoing in state court. The utilities and Bernalillo County reached a standstill 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 challenges to the ordinance are unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS’ fuel cost adjustment clause practices and issues relating to demand cost allocation (the “Golden Spread Proceeding”). In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM (“SPS 2006 Rate Proceeding”). In 2008, FERC issued its order in the Golden Spread Proceeding affirming an ALJ decision that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues that had been ordered by the ALJ.  FERC also reversed the decision of the ALJ, which had been favorable to PNM, on the demand cost allocation issues. PNM and SPS filed petitions for rehearing and clarification of the scope of the remedies that were ordered and seeking reversal of various rulings in the order. On August 15, 2013, FERC issued separate orders in the Golden Spread Proceeding and in the SPS 2006 Rate Proceeding. The order in the Golden Spread Proceeding determined that PNM was not entitled to refunds for SPS’ fuel cost adjustment clause practices. That order and the order in the SPS 2006 Rate Proceeding decided the demand cost allocation issues using the method that PNM had advocated.  PNM, SPS, and other customers of SPS have filed requests for rehearing of these orders and they are pending further action by FERC. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes.

Navajo Nation Allottee Matters

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. 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.  On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested.  The letter indicated that the renewals were not approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. On July 13, 2015, PNM filed a condemnation action in the United States District Court for the District of New Mexico regarding the approximately 15.49 acres of land at issue. PNM cannot predict the outcome of this litigation.

(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 2014 Annual Reports on Form 10-K.

PNM

2014 Electric Rate Case

On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future test year (“FTY”) period. The application proposed a revenue increase of $107.4 million, effective January 1, 2016. PNM’s proposed ROE was 10.5%. The requested base rate increase, combined with other rate changes, represented an average bill increase of 7.69%. PNM requested this increase to account for infrastructure investments made since the last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect the declining sales growth in PNM’s service territory. The primary driver of PNM’s identified revenue deficiency, accounting for approximately 92% of the rate increase, was related to infrastructure investments and the recovery of those investment dollars, including depreciation. PNM’s success with energy efficiency programs was a contributing factor to the decline in PNM’s energy sales since the last rate case and accounted for the balance of the rate increase after accounting for offsetting cost reductions. PNM proposed several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals included increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, an access charge to customers installing distributed generation systems after December 31, 2015, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. Several parties filed briefs, which alleged that PNM’s application was incomplete and challenged the distributed generation charge, as well as other aspects of PNM’s filing. PNM filed a response brief addressing these matters.

On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it on the grounds that it does not comply with the FTY rule. The Hearing Examiner cited procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. The Hearing Examiner recommended that PNM be granted the ability to keep the calendar year 2016 future test period and that PNM could reapply for a general rate increase by remedying the files and providing other supporting documents. PNM did not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argued that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision established an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullified the future test year statute.  PNM further argued that its application should be suspended, rather than dismissed. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision regarding the completeness of PNM’s application

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

and dismissed PNM’s application. This NMPRC order did not address the Hearing Examiner’s recommendation regarding when a future test period could begin relative to a rate case application date.

On May 27, 2015, the NMPRC approved an order that defines a FTY as a period that begins no later than 45 days following the filing of an application to increase rates. PNM disagrees with the interpretation adopted by the NMPRC and believes that the correct interpretation of the New Mexico FTY statute allows a FTY to begin up to 13 months after the filing of an application.

On June 25, 2015, PNM filed a Notice of Appeal to the New Mexico Supreme Court, challenging the NMPRC’s June 3, 2015 written order. There is no required timeframe for the New Mexico Supreme Court to act on PNM’s appeal. Two other utilities have filed separate notices of appeals with the Supreme Court and ABCWUA filed a notice of cross appeal. On July 15, 2015, the NMPRC filed its Motion for Stay of Proceeding at Supreme Court and for Remand of Jurisdiction, seeking the ability to conduct a rulemaking process on the definition and parameters of a FTY for rate cases. PNM opposes the motion. Responses to the motion are due August 17, 2015. On July 31, 2015, PNM and the NMPRC filed a joint motion for a limited 30-day stay and remand of PNM’s appeal so that the NMPRC can reconsider its FTY order in PNM’s 2014 rate case; this motion is opposed by ABCWUA.

Based on the above NMPRC rulings, PNM currently anticipates filing, in the third quarter of 2015, a new application with the NMPRC to increase rates. The contemplated rate request would be updated to include current circumstances. New rates would be expected to become effective in the third quarter of 2016.

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, which are subject to the limitation of the RCT, are 30% wind, 20% solar, 5% other, and 3% distributed generation.

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.

PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements included 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. The NMPRC approved the plan on December 18, 2013. PNM made procurements in 2014 consistent with the approved plan. Construction of the solar PV facilities was completed in 2014 at a cost of $46.5 million.

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 included 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). A stipulated settlement was approved by the NMPRC on November 26, 2014. Under the agreement, the costs of the 40 MW of solar would be included in base rates rather than through PNM’s renewable energy rider and have been included in rates requested in the 2014 Electric Rate Case discussed above. In addition, PNM would be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT at a not-to-exceed price of $3.00 per MWh in 2013 and 2014. In the fourth quarter of 2014 and the second quarter of 2015, PNM procured the additional renewable resources to meet the 2013 and 2014 RPS requirement for $0.1 million and less than $0.1 million. The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan meets RPS and diversity requirements within the RCT in 2016 and 2017. The plan does not propose any significant new procurements. A public hearing on the 2016 procurement plan is scheduled to begin on September 1, 2015 and an order from the NMPRC is expected by November 30, 2015.

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 electric 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. PNM made filings with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013 and 2014 on April 1, 2014 and April 1, 2015. PNM recorded revenues from the rider of $34.3 million in 2014. In PNM’s 2015 renewable energy procurement plan case, the NMPRC approved a rate, which is designed to collect $44.7 million in 2015. On February 27, 2015, PNM filed a notice to reduce the amount to be collected during 2015 to $43.0 million, reflecting a reconciliation of expenses and revenues under the rider during 2014 and updated cost estimates for 2015. The rate reduction was due to an over-collection in 2014 that primarily resulted from lower than projected generation of geothermal renewable energy. The revision was implemented on April 27, 2015. PNM proposes to recover $42.4 million through the rider in 2016 in its 2016 renewable energy procurement plan.

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. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s 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.

On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. PNM and the NMPRC staff filed a stipulation on January 30, 2015. A public hearing on the stipulation was held in February 2015. The Hearing Examiner issued a Certification of Stipulation on April 10, 2015 recommending that the NMPRC approve the stipulation in its entirety and to allow PNM to continue recovering the incentive contemporaneously with program costs. On April 29, 2015, the NMPRC approved the certification. Upon approval, the stipulation established program budgets and the incentive amounts discussed below.

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

In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million. PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. Under the terms of the January 30, 2015 stipulation discussed above, the incentive amount would be $1.7 million in 2015 and $1.8 million in 2016 assuming threshold level of savings are achieved.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. The NMPRC issued an order on October 8, 2014 adopting the proposed rule, which includes a provision that limits incentive awards to an amount equal to the utility’s WACC times its approved annual program costs.

Integrated Resource Plan

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3.

San Juan Generating Station Units 2 and 3 Retirement

On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommends rejection of the agreement as proposed, and recommended several modifications to the agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation and certification, is set forth in Note 11. PNM anticipates an order from the NMPRC in the fourth quarter of 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 February 17, 2015, PNM received notice from EPE that EPE has entered into an agreement to sell its 7% interest in Four Corners to APS, thereby triggering PNM’s ability to exercise its right of first refusal (“ROFR”) to acquire a portion of EPE’s interest in Four Corners. PNM notified the NMPRC about receipt of the notice and advised the NMPRC that PNM does not intend to exercise its rights under the ROFR. The ROFR expired unexercised 120 days from the date of the notice.

Application for Certificate of Convenience and Necessity

On June 30, 2015, PNM filed an application for a CCN for a 187 MW gas plant to be located at SJGS. This resource was identified as a replacement resource in PNM’s application to retire SJGS Units 2 and 3. PNM estimates the cost of the facility to be $133.2 million. PNM identified the necessary in-service date to be in the first half of 2018. On July 9, 2015, a party filed a motion to consolidate this case with the SJGS Unit 2 and 3 retirement case. The NMPRC has not yet acted on PNM’s application or on the motion. PNM cannot predict the outcome of this proceeding.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Formula Transmission Rate Case

In a settlement of a prior rate case for PNM’s transmission customers, the parties agreed that if PNM filed for a formula based rate change, no party would oppose the general principle of a formula rate, although the parties could object to particular aspects of the formula. 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. The 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 approved in the previous rate case. The new rates apply to all of PNM’s wholesale electric transmission service customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates on April 1, 2015, subject to refund. There is no required time frame for FERC to act upon the settlement.

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc.

In September 2011, PNM filed an unexecuted amended power sales agreement (“PSA”) between PNM and NEC with FERC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and amended PSA, which were filed with FERC on December 6, 2012. The settlement agreement and amended PSA provided for an annual increase in revenue of $5.3 million and an extension of the contract for 10 years through December 31, 2035. On April 5, 2013, FERC approved the settlement agreement and the amended PSA. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement.

On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under the amended PSA. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both the intent of the amended PSA for PNM to supply NEC’s long-term power requirements and the amended PSA’s provision that expressly disallows termination of the agreement before December 31, 2035. NEC has asked for FERC to act on the petition by September 30, 2015. On May 8, 2015, PNM filed an intervention with FERC requesting that FERC deny NEC’s petition or to proceed with a public hearing if the petition is not denied. On July 16, 2015, FERC issued an order setting the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA, and holding the hearing in abeyance to provide time for settlement judge procedures, which have begun. PNM is unable to predict the outcome of this matter.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility.  PNM’s contract with Gallup ended on June 29, 2014.  PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014. PNM’s 2014 Electric Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.

In conjunction with the termination of PNM’s electric service agreement with Gallup, Gallup purchased substations and associated transmission facilities owned by PNM that had been used solely to provide service to Gallup. This sale resulted in a gain of $1.1 million, which PNM recorded in other income during the three months ended June 30, 2015.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 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.

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 is to be borne by opt-out customers through an initial fee and ongoing monthly charge. On June 20, 2014, the PUCT approved a settlement permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of July 24, 2015, 96 customers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On October 25, 2013, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.6 million, including a performance bonus for 2012 of $0.7 million, beginning March 1, 2014. On September 11, 2014, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.7 million beginning March 1, 2015, including a performance bonus for 2013 of $1.5 million. On May 29, 2015, TNMP filed its 2016 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.9 million, including a performance bonus of $0.6 million, to be collected beginning March 1, 2016. A hearing on the application is scheduled for August 28, 2015. TNMP records incentive bonuses upon approval by 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,

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(Unaudited)

and the approved rate of return on such facilities. The following sets forth TNMP’s most recent interim transmission cost rate increases:

Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 17, 2013	$	18.1	$	2.8
March 13, 2014	18.2		2.9
September 8, 2014	25.2		4.2
March 16, 2015	27.1		4.4

On July 17, 2015, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $7.0 million, which would increase revenues by $1.4 million annually. The application is pending before the PUCT.

(13) Income Taxes

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 is being 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. 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 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. 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, 2015 and 2014, PNM’s regulatory liability was reduced by $2.0 million and $4.6 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment; and were reduced by $0.2 million in the three months ended March 31, 2014 increasing income tax expense in the Corporate and Other segment.

In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008. 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.

On December 19, 2014, the Tax Increase Prevention Act of 2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law.  Due to provisions in the act, taxes payable to the State of New Mexico were reduced. The act resulted in an impairment of New Mexico net operating loss carryforwards, which was recorded as additional income tax expense during the year ended December 31, 2014. During the three months ended March 31, 2015, the impairment of the New Mexico net operating loss carryforward was refined, resulting in an additional impairment of $1.0 million, after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. TNMP had no such impairment.

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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)

(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,
	2015		2014		2015		2014
	(In thousands)
Services billings:
PNMR to PNM	$	21,340	$	22,190	$	44,067	$	43,256
PNMR to TNMP	6,591		6,963		13,680		14,224
PNM to TNMP	184		133		288		242
TNMP to PNMR	—		—		—		—
Interest billings:
PNMR to TNMP	54		83		133		180
PNMR to PNM	22		—		28		54
PNM to PNMR	26		25		55		51
Income tax sharing payments:
PNMR to PNM	—		—		1,450		—
PNMR to TNMP	—		—		—		—

(15) Goodwill

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

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

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

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis,

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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)

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, 2015 and 2014, 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, 2015 and 2014 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2015 and 2014 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 25% and 30%. 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, 2015 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 20 of Notes to Consolidated Financial Statements in the 2014 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 756,000 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 its solid 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

• 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 filed a general rate case with the NMPRC in December 2014. PNM’s application proposed a revenue increase of $107.4 million, effective January 1, 2016, based on a calendar 2016 future test year (“FTY”) and a ROE of 10.5%. PNM requested this increase to account for infrastructure investments made since its last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect declining sales growth in PNM’s service territory. The infrastructure investments accounted for approximately 92% of the rate increase. PNM’s success with energy efficiency programs was a contributing factor to the decline in sales growth and accounted for the balance of the rate increase after offsetting cost reductions. PNM proposed several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation, including an access charge to customers installing distributed generation systems after December 31, 2015.

On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it. The Hearing Examiner did not comment on the validity of PNM’s requested rates, but cited procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the FTY period. The Hearing Examiner recommended that PNM be granted the ability to keep the

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calendar year 2016 future test period and that PNM could reapply for a general rate increase by remedying the files and other supporting documents. PNM disagreed with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argued that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision established an unreasonable standard for FTY filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullified the FTY statute.  PNM further argued that its application should be suspended, rather than dismissed. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision and dismissed PNM’s application.

In addition, on May 27, 2015, the NMPRC approved an order that defines a FTY as a period that begins no later than 45 days following the filing of an application to increase rates. PNM disagrees with the interpretation adopted by the NMPRC and believes that the correct interpretation of the New Mexico FTY statute allows a FTY to begin up to 13 months after the filing of an application. On June 25, 2015, PNM filed a Notice of Appeal to the New Mexico Supreme Court, challenging the NMPRC’s order. There is no required timeframe for the New Mexico Supreme Court to act on PNM’s appeal. Several other utilities have filed separate notices of appeals with the Supreme Court and one party to PNM’s rate case filed a notice of cross appeal. The NMPRC has requested that the Supreme Court remand the matter back to the NMPRC in order to conduct a rulemaking process on the definition and parameters of a FTY for rate cases.

Based on the above NMPRC rulings, PNM currently anticipates filing, in the third quarter of 2015, a new application with the NMPRC to increase rates. The contemplated rate request would be updated to include current circumstances. New rates would be expected to become effective in the third quarter of 2016. If the NMPRC’s ruling that defines a FTY remains in effect, PNM would likely file more frequent applications for rate increases with the NMPRC.

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 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.

In early 2013, PNM completed rate proceedings for all of its FERC regulated transmission customers and for NEC, its largest generation services customer, which improved PNM’s returns for providing those services. However, the contract to provide power to Gallup, PNM’s second largest customer for wholesale generation services, ended on June 29, 2014. PNM’s general rate case application discussed above included a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. PNM has an agreement to supply power to NEC through 2035, which was approved by FERC in April 2013. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under that agreement. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both the intent for PNM to supply NEC’s long-term power requirements and the agreement’s provision that expressly disallows termination of the agreement before December 31, 2035. NEC has asked for FERC to act on the petition by September 30, 2015. PNM has filed an intervention with FERC requesting that FERC deny NEC’s petition. On July 16, 2015, FERC issued an order setting the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA, and holding the hearing in abeyance to provide time for settlement judge procedures, which have begun. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement. PNM is unable to predict the outcome of this matter.

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. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. There is no required time frame for FERC to act upon the settlement.

Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2014 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 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.

Currently, PNM’s 134 MW interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates. The power generated from that interest is sold into the wholesale market and any earnings or losses are realized by shareholders. While PVNGS Unit

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3’s financial results are not included in the authorized returns on its regulated business, it impacts PNM’s earnings and has been demonstrated to be a valuable asset. As part of compliance with the requirements for BART at SJGS discussed below, PNM has requested NMPRC approval to include PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018.

Maintaining Investment Grade Credit Ratings

PNM is committed to maintaining investment grade credit ratings. See the subheading Liquidity included in the full discussion of Liquidity and Capital Resources below for the specific credit ratings for PNMR, PNM, and TNMP. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade.

Providing Top-Quartile Total Returns to Investors

PNMR’s strategic goal to provide top quartile total return to investors over the 2012 to 2016 period is based on five-year ongoing earnings per share growth plus five-year average dividend yield from a group of regulated electric utility companies with similar market capitalization. Top quartile total return currently is equal to an average annual rate of 10% to 13%. Ongoing earnings, which is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP.

PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. The annual common stock dividend was raised by 16% in February 2012, 14% in February 2013, 12% in December 2013, and 8% in December 2014. 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

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

Reliable and Affordable Power

PNMR and its utilities are aware of the important roles they play in enhancing economic vitality in their New Mexico and Texas service territories. Management believes that maintaining strong and modern electric infrastructure is critical to ensuring reliability and economic growth. When considering expanding or relocating to other communities, businesses consider energy affordability and reliability to be important factors. PNM and TNMP strive to balance service affordability with infrastructure investment to maintain a high level of electric reliability and to deliver a superior customer experience. The utilities also work to ensure that rates reflect actual costs of providing service.

Investing in PNM’s and TNMP’s infrastructure is critical to ensuring reliability and meeting future energy needs. Both utilities have long-established records of providing customers with reliable electric service. For three out of the last five years, both PNM and TNMP have ranked in the top quartile nationally for reliability. In 2014, PNM delivered its best reliability performance in the past seven years and TNMP’s reliability was its best in a decade.

In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through June 30, 2015, TNMP had completed installation of more than 201,000 smart meters, which is approximately 84% 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. TNMP is also installing a new outage management system that will leverage capabilities of the smart meters to enhance TNMP’s responsiveness to outages.

During the 2012 to 2014 period, PNM and TNMP together invested $1,062.8 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. Construction began in April 2015 and the

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facility is expected to go into service in late 2015. As discussed below, on June 30, 2015, PNM filed an application for a CCN for a 187 MW gas-fired peaking generating station to be sited at SJGS.

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.

Environmentally Responsible Power

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

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

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

•Increasing energy efficiency participation

Another area of emphasis is the reduction of the amount of fresh water used during electricity generation at PNM’s power plants. The fresh water used per MWh generated has dropped by 25% since 2002, primarily due to the growth of renewable energy sources, the expansion of Afton to a combined-cycle plant that has both air and water cooling systems, and the use of gray water for cooling at Luna. As discussed below, PNM has requested approval to shut down SJGS Units 2 and 3, which would reduce water consumption at that plant by about 50%. In addition to the above areas of focus, the Company is working to reduce the amount of solid waste going to landfills through increased recycling and reduction of waste. The Company has performed well in this area in the past and expects to continue to do so in the future.

Renewable Energy

PNM’s renewable procurement strategy includes utility-owned solar capacity, as well as wind and geothermal energy purchased under PPA’s. As of January 1, 2015, PNM had 67 MW of utility-owned solar capacity, including 23 MW completed in 2014. PNM is currently constructing an additional 40 MW of PNM-owned solar PV facilities, which are contemplated in PNM’s application to retire SJGS Units 2 and 3 discussed below. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 42 MW at June 30, 2015. PNM also 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.

Since 2003, PNM has a PPA for the output from a 204 MW wind facility and began purchasing the output of another existing 102 MW wind energy center on January 1, 2015. PNM has 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 also purchases RECs to meet the RPS.

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. PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM’s 2015 renewable energy procurement plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM will continue to procure renewable resources while balancing the impact to customers’ bills 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 2014 Annual Reports on Form 10-K and in Note 11.

In August 2011, EPA issued a FIP for regional haze that would have required the installation of SCRs on all four units at SJGS by September 2016. Following approval by the majority of the other SJGS owners, PNM, NMED, and EPA agreed on

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February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a RSIP from the State of New Mexico. The RSIP has been approved by the EIB and EPA. Installation of SNCRs and BDT on SJGS Unit 1 was completed in April 2015 and PNM anticipates that installation of SNCRs and BDT on Unit 4 can be completed within the timeframe contained in the RSIP.

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

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

Under the terms of the stipulation, PNM would:

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

• Acquire an additional 132 MW of SJGS Unit 4

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

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

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

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

A public hearing in the NMPRC case was held in January 2015. If the stipulation is approved as filed, PNM anticipates that upon approval it would incur a regulatory disallowance, which would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. PNM currently estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million. See Note 11.

On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommends that the NMPRC reject the stipulation as proposed. The certification recommends that the abandonment of SJGS Units 2 and 3 be conditionally approved subject to PNM proposing adequate replacement capacity, approval of the CCN for PVNGS Unit 3 at its net book value at January 1, 2018, which is estimated to be $143.5 million ($1,071/KW), approval of recovery of an estimated $128.5 million, representing 50% of the remaining undepreciated investment in SJGS Units 2 and 3, and denial of the CCN for the additional 132 MW of Unit 4 of SJGS. The certification states that PNM may re-apply for a CCN for the 132 MW after it has presented final restructuring and post-2017 coal supply agreements for SJGS. On April 20, 2015, PNM filed exceptions to the certification. PNM argued that the proposed modifications to the stipulation do not balance customer and shareholder interests, upset the balance contained in the stipulation, that the schedule recommended by the Hearing Examiner for PNM to file a replacement plan would effectively preclude the inclusion of the 132 MW of additional SJGS Unit 4 capacity in the replacement plan thereby jeopardizing the restructuring agreement and the continued operation of SJGS to the detriment of customers, and that the Hearing Examiner erred in recommending a lower rate base value for PNM’s share of PVNGS Unit 3. If the NMPRC issues an order that modifies the stipulation, any stipulating party can void the stipulation. The NMPRC can approve, reject, or modify the certification. If the NMPRC were to issue an order adopting all of the modifications to the stipulation recommended by the Hearing Examiner, PNM estimates the net pre-tax regulatory disallowance referenced above would become an amount between $145 million and $155 million.

The December 20, 2013 filing also identified a new 177 MW natural gas-fired generation source and 40 MW of new utility-scale solar generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. The additional solar capacity is included in PNM’s 2015 renewable procurement strategy (Note 12). On

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June 30, 2015, PNM filed an application with the NMPRC for a CCN to construct, own, and operate the additional gas facility, which is now anticipated to be rated at 187 MW, and the treatment of associated costs. PNM requested that the NMPRC establish a schedule that would enable the NMPRC to act upon the application by May 2016.

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 began negotiating 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.

In June 2014, non-binding arrangements were reached among the SJGS owners that identified 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. These arrangements provided the essential terms of restructured ownership of SJGS. These arrangements recognized the need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. See Coal Supply in Note 11. On January 7, 2015, one of the participants in SJGS Unit 4 notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs unsubscribed in that unit. Although PNM indicated that it would not acquire any of the unsubscribed MWs, PNMR indicated that PNMR Development would acquire the 65 MWs.

In May 2015, PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 entered into an agreement, which provides PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. PNMR’s current projection of capital expenditures includes those related to the 65 MW.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of a confidential, substantially final, unexecuted copy of the San Juan Project Restructuring Agreement (“RA”). The RA sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the June 2014 arrangements. On December 31, 2017, PNM would acquire 132 MW of the capacity in SJGS Unit 4 from the California owners and PNMR Development would acquire 65 MW of such capacity. The RA is dependent on and would become effective upon the last of the approval by NMPRC, the approval by FERC, the approval of each participant’s board or other decision-making body, and the effective date of a new coal supply agreement for SJGS. PNM’s notice also included the submittal of a confidential, substantially final, unexecuted copy of a new coal supply agreement. The coal supply agreement and the RA will become effective contemporaneously, which is currently anticipated to be on January 1, 2016. Under the RA, PNM would acquire the coal inventory of the exiting SJGS participants on January 1, 2016 and provide coal supply to the exiting participants during the period from January 1, 2016 through December 31, 2017, which arrangement PNM believes will provide economic benefits to PNM. PNM anticipates that coal costs under the CSA will be significantly less than under the current arrangement with SJCC. Since substantially all coal costs are passed through PNM’s FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners will be passed through to PNM’s customers. The RA also includes provisions whereby the exiting owners will make payments to certain of the remaining participants, not including PNM, related to the restructuring.

On May 27, 2015, the NMPRC issued an order requiring PNM to file executed restructuring and coal supply agreements by July 1, 2015, which was subsequently extended to August 1, 2015. On July 1, 2015, PNM filed the executed coal supply and related agreements described under Coal Supply in Note 11 with the NMPRC. On July 1, 2015, PNM also filed partially executed agreements related to restructuring. On July 31, 2015, PNM filed fully executed restructuring agreements.

The NMPRC has designated a facilitator to determine whether an uncontested settlement among some or all of the parties in this case could be accomplished and a mediation process is on-going. A public hearing is scheduled to begin on September 30, 2015. Although PNM expects a decision from the NMPRC in the fourth quarter of 2015, PNM is unable to predict what action the NMPRC will take, whether any party will void the stipulation, or the ultimate outcome of this matter.

PNM is unable to predict whether required approvals will be obtained and other conditions satisfied in order for the agreements discussed above to become effective and restructuring to be consummated.

PNM, as the SJGS operating agent, presented the SNCR project to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. PNM is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending resolution by the participants. In March 2014, June 2014, and January 2015, PNM requested that the owners of Unit 4 approve

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expenditures critical to being able to comply with the time frame in the RSIP with respect to Unit 4 project. The Unit 4 owners did not approve the requests. In March 2014, July 2014, and March 2015, PNM issued “Prudent Utility Practice” notices that, under the SJPPA, PNM was continuing certain critical activities to keep the Unit 4 project on schedule.

In addition to the regional haze rule, SJGS is required to comply with other rules currently being developed or implemented that affect coal-fired generating units, including recently proposed rules regarding GHG under Section 111(d) of the CAA. Because of environmental upgrades completed in 2009, SJGS is well positioned to outperform the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. The major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO₂, particulate matter, and mercury. Since 2006, SJGS has reduced NOx emissions by 42%, SO₂ by 67%, particulate matter by 71%, and mercury by 95%.

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 2014, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 70 GWh. This is equivalent to the annual consumption of approximately 9,700 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 2014 resulted in energy savings totaling an estimated 17 GWh. This is equivalent to the annual consumption of approximately 1,600 homes in TNMP’s service territory.

Creating Value for Customers and Communities

The Company strives to deliver a superior customer experience by understanding the dynamic needs of its customers through ongoing market research, identifying and establishing best-in-class services and programs, and proactively communicating and engaging with customers at a regional and community level. Beginning 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, including billing and payment options, and strategic customer and stakeholder engagement.

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

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

PNM expanded its integrated communication efforts with the launch of a new customer information website focused on PNM’s major regulatory filings, including the stipulated settlement agreement regarding BART at SJGS and PNM’s general rate case. The website, www.PowerforProgress.com, provides the details of current requests, as well as the background on PNM’s efforts to maintain reliability, keep prices affordable, and protect the environment. The website is designed to be a resource for the facts about PNM's operations and community support efforts, including plans for building a sustainable energy future for New Mexico.

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 2014, PNM hosted 31 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 3,153 families in

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2014. In 2014, PNM committed funding of $0.4 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 2014, the foundation awarded $0.2 million to support 54 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 $1.6 million of support. 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 $0.5 million were awarded to 24 nonprofits in New Mexico and Texas for projects ranging from creating community gathering spaces to revitalizing neighborhood parks to building a youth sports field.

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

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

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

Economic Factors

In the six months ended June 30, 2015, PNM experienced a decrease in weather normalized retail load of 1.2% compared to 2014.  There continue to be signs the New Mexico’s economy is stabilizing. However, economic growth continues to be slow and the economic data provides conflicting indicators. The New Mexico unemployment rate has decreased from the prior year, but is still above the national average. Housing prices in New Mexico increased in the first quarter of 2015 compared to the first quarter of 2014, but Albuquerque’s output has reportedly decreased. In the six months ended June 30, 2015, TNMP’s weather normalized retail load increased 3.5% compared to 2014. Since the recent recession, Texas has fared better than the national average in unemployment. However, employment growth is a stronger predictor of load. Texas’ employment growth rates are well above the national rate, while New Mexico’s employment is showing modest growth.

Results of Operations

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

	Three Months Ended June 30,							Six Months Ended June 30,
	2015		2014		Change			2015		2014		Change
	(In millions, except per share amounts)
Net earnings attributable to PNMR	$	31.7	$	29.1	$	2.5		$	46.0	$	41.6	$	4.4
Average diluted common and common equivalent shares	80.1		80.2		(0.1		)	80.1		80.3		(0.2		)
Net earnings attributable to PNMR per diluted share	$	0.40	$	0.36	$	0.04		$	0.57	$	0.52	$	0.05

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

	Three Months Ended			Six Months Ended
	June 30, 2015			June 30, 2015
	(In millions)
PNM	$	1.2		$	3.6
TNMP	2.4			3.3
Corporate and Other	(1.0		)	(2.4		)
Net change	$	2.5		$	4.4

PNMR’s operational results were affected by the following:

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

• Rate increases for PNM and TNMP – additional information about these rate increases is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and Note 12

• Reduced rent payments upon renewal of leases for PVNGS Unit 1

• A refund of amounts previously paid under the FERC tariff for gas transportation agreements

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

• Fluctuations in prices for sales of power from PVNGS Unit 3

• 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 2019. 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 $719.7 million at July 24, 2015. 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 $2,555.5 million for 2015-2019, including amounts expended through June 30, 2015. 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, environmental upgrades at Four Corners, the purchase of the leased portion of the EIP, and the purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases. 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 2015-2019 period. The Company currently believes that its internal cash generation, existing credit arrangements, and access to public and private capital markets will provide sufficient resources to meet the Company’s capital requirements.

RESULTS OF OPERATIONS

Segment Information

The following discussion is based on the segment methodology that PNMR’s management uses for making operating decisions and assessing performance of its various business activities. See Note 3 for more information on PNMR’s operating segments.

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

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PNM

The following table summarizes the operating results for PNM:

	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Change			2015			2014			Change
	(In millions)
Electric operating revenues	$	275.5		$	275.7		$	(0.2	)	$	537.4		$	538.4		$	(1.0	)
Cost of energy	95.7			92.6			3.1			193.6			189.3			4.3
Margin	179.7			183.1			(3.4		)	343.8			349.2			(5.4		)
Operating expenses	103.5			106.2			(2.7		)	207.6			214.0			(6.4		)
Depreciation and amortization	29.0			27.0			2.0			57.4			54.1			3.3
Operating income	47.2			49.8			(2.6		)	78.8			81.1			(2.3		)
Other income (deductions)	9.4			7.6			1.8			17.0			11.4			5.6
Net interest charges	(19.7		)	(20.0		)	0.3			(39.6		)	(39.8		)	0.2
Segment earnings before income taxes	36.9			37.4			(0.5		)	56.2			52.6			3.6
Income (taxes)	(11.5		)	(13.1		)	1.6			(17.3		)	(17.2		)	(0.1		)
Valencia non-controlling interest	(3.9		)	(3.9		)	—			(7.2		)	(7.4		)	0.2
Preferred stock dividend requirements	(0.1		)	(0.1		)	—			(0.3		)	(0.3		)	—
Segment earnings	$	21.4		$	20.2		$	1.2		$	31.4		$	27.8		$	3.6

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

	2014/2015 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	$	(1.9	)	$	—		$	(1.9	)	$	(3.4	)	$	—		$	(3.4	)
Weather	(3.7		)	—			(3.7		)	(4.0		)	—			(4.0		)
Transmission	(1.4		)	(0.1		)	(1.3		)	(2.2		)	—			(2.2		)
FPPAC	13.4			13.4			—			22.3			22.3			—
Economy energy service	(0.6		)	(0.6		)	—			(2.8		)	(2.7		)	(0.1		)
Rio Bravo purchase	—			(1.7		)	1.7			—			(3.3		)	3.3
Unregulated margin	0.1			(1.0		)	1.1			(0.6		)	(0.4		)	(0.2		)
Wholesale contracts	(2.3		)	(0.6		)	(1.7		)	(5.0		)	(1.6		)	(3.4		)
Energy efficiency rider	(0.1		)	—			(0.1		)	0.4			—			0.4
Renewable energy rider	2.6			1.0			1.6			2.8			1.0			1.8
Net unrealized economic hedges	(3.9		)	0.1			(4.0		)	(2.6		)	0.3			(2.9		)
Non-FPPAC off-system activity	(1.1		)	(1.4		)	0.3			(4.3		)	(4.7		)	0.4
El Paso Natural Gas Refund	—			(4.2		)	4.2			—			(4.2		)	4.2
Other	(1.3		)	(1.8		)	0.5			(1.6		)	(2.4		)	0.8
Net change	$	(0.2	)	$	3.1		$	(3.4	)	$	(1.0	)	$	4.3		$	(5.4	)

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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,
	2015			2014			Change			2015			2014			Change
	(In millions, except customers)
Residential	$	94.1		$	92.7		$	1.4		$	200.9		$	190.4		$	10.5
Commercial	116.8			109.2			7.6			210.6			198.9			11.7
Industrial	19.0			17.3			1.7			35.9			33.1			2.8
Public authority	6.2			6.0			0.2			11.8			11.2			0.6
Economy service	9.4			10.0			(0.6		)	17.8			20.6			(2.8		)
Other retail	2.6			1.7			0.9			4.1			5.2			(1.1		)
Transmission	8.4			9.7			(1.3		)	16.5			18.8			(2.3		)
Firm-requirements wholesale	7.3			10.4			(3.1		)	15.5			21.9			(6.4		)
Other sales for resale	16.1			19.1			(3.0		)	30.3			41.7			(11.4		)
Mark-to-market activity	(4.4		)	(0.4		)	(4.0		)	(6.0		)	(3.4		)	(2.6		)
	$	275.5		$	275.7		$	(0.2	)	$	537.4		$	538.4		$	(1.0	)
Average retail customers (thousands)	514.3			510.8			3.5			514.0			510.6			3.4

The following table shows GWh sales by customer class:

	Three Months Ended June 30,				Six Months Ended June 30,
	2015	2014	Change		2015	2014	Change
	(Gigawatt hours)
Residential	692.6	731.2	(38.6	)	1,478.7	1,506.2	(27.5	)
Commercial	987.8	1,005.2	(17.4	)	1,822.2	1,873.2	(51.0	)
Industrial	232.6	242.7	(10.1	)	465.5	482.6	(17.1	)
Public authority	57.9	63.1	(5.2	)	110.0	114.7	(4.7	)
Economy service	200.4	192.1	8.3		396.0	383.6	12.4
Firm-requirements wholesale	102.1	149.4	(47.3	)	214.5	310.2	(95.7	)
Other sales for resale	547.0	539.0	8.0		1,011.6	1,122.9	(111.3	)
	2,820.4	2,922.7	(102.3	)	5,498.5	5,793.4	(294.9	)

For the three and six months ended June 30, 2015, retail sales were lower compared to 2014 reflecting a continued sluggish economy in New Mexico. In particular, the Albuquerque metropolitan area has lagged the nation in economic recovery. However, there continue to be signs that New Mexico’s economy is stabilizing. Job growth has improved with several local businesses making announcements of new jobs. The New Mexico unemployment rate is 6.4%, compared to the national average of 5.3%, although the New Mexico rate is an improvement from 7.0% in the first quarter of 2014. New Mexico housing prices increased 1.5% in the first quarter of 2015 compared to the first quarter of 2014, but the Brookings Institute has indicated that Albuquerque’s output decreased 0.6% for the quarter. Overall economic growth continues to be slow. In spite of these economic pressures, PNM experienced an increase in the average number of retail customers of 0.7% and 0.7% for the three and six months ended June 30, 2015 compared to 2014. PNM’s weather normalized retail KWh sales were 1.2% lower for the three and six months ended June 30, 2015 compared to 2014, which decreased revenues and margin $1.9 million and $3.4 million in 2015 compared to 2014. Weather negatively impacted revenues and margin $3.7 million and $4.0 million during the three and six months ended June 30, 2015 compared to 2014. For the three months ended June 30, 2015, cooling degree days were 18.2% lower than in 2014. Heating degree days were 1.7% and 0.2% lower for the three and six months ended June 30, 2015 than in 2014. 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.

For the three and six months ended June 30, 2015, transmission revenues decreased by $1.4 million and $2.2 million and margin decreased by $1.3 million and $2.2 million compared to 2014. These decreases primarily resulted from the expiration of two long-term point-to-point contracts aggregating $0.9 million and $1.9 million for the three and six months ended June 30, 2015 compared to 2014. Lower short-term point-to-point transmission revenues decreased revenues and margin $0.6 million and $0.7 million for the three and six months ended June 30, 2015 compared to 2014. The decreases were partially offset by a May 2014

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rate increase under PNM’s formula-based transmission rate case, which increased revenues $0.2 million and $0.5 million during the three and six months ended June 30, 2015.

In April 2014, the NMPRC approved the continuation of PNM’s FPPAC and authorized PNM to recover the remaining under-collected balance in its FPPAC balancing account over 18 months effective July 1, 2014. As a result PNM’s revenues increased in 2015 compared to 2014. These revenue increases were offset in cost of energy with no impact on margin.

PNM provides economy energy services to a major customer. Under this contract, PNM purchases energy on the customer’s behalf and delivers the energy to the customer’s location through PNM’s transmission system. PNM charges the customer for the cost of the energy as a direct pass through to the customer with no impact to PNM’s margin. Although revenue from this customer decreased for the three and six months ended June 30, 2015 compared to 2014, there is only a minor impact on margin, which results from providing ancillary services.

PNM closed on the acquisition of Rio Bravo, formerly known as Delta, on July 17, 2014. Prior to acquiring Rio Bravo, PNM had a 20 year PPA covering all of the output of the facility. PNM accounted for the PPA as an operating lease and recorded fixed and variable costs in cost of energy. As a result of the Rio Bravo acquisition, cost of energy decreased and margin increased $1.7 million and $3.3 million for the three and six months ended June 30, 2015 compared to 2014. The increase in margin is partially offset by increases in operating and depreciation expenses.

Unregulated revenues and margin are primarily associated with PVNGS Unit 3, which currently is not regulated by the NMPRC. Power from PVNGS Unit 3 is sold on the open market. Lower market prices for power in the first quarter of 2015 resulted in revenues being $0.7 million lower for the six months ended June 30, 2015 than in 2014. Lower nuclear fuel costs decreased cost of energy $0.3 million and $0.7 million for the three and six months ended June 30, 2015 compared to 2014. Nuclear spent fuel reimbursements from the DOE decreased cost of energy and increased margin $0.7 million and $1.9 million for the three and six months ended June 30, 2015 compared to 2014. See Note 11. In addition, gas imbalance settlements lowered cost of energy $2.1 million in the six months ended June 30, 2014, which settlements did not recur in 2015.

PNM’s contract with Gallup, its second largest wholesale generation customer, expired on June 29, 2014. For the three months ended June 30, 2015, a $2.9 million decrease in revenues from the Gallup contract was partially offset by an increase in off-system sales of $0.8 million from power that would have otherwise been used to serve Gallup and lower fuel expense of $0.4 million. For the six months ended June 30, 2015, a $6.1 million decrease in revenues from the Gallup contract was partially offset by an increase in off-system sales of $1.4 million and lower fuel expense of $1.3 million. PNM’s rate case application, filed in December 2014, which was subsequently dismissed by the NMPRC, included a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. See Note 12.

In August 2012, PNM implemented its renewable energy rider, which recovers certain renewable energy procurement costs to meet the RPS. In January 2015, PNM increased the rate charged under the rider to include PNM-owned solar PV facilities completed in 2014. See Note 12. For the three and six months ended June 30, 2015, this rider increased revenues by $2.6 million and $2.8 million compared to 2014. These revenues include a return on investment of $1.7 million and $3.5 million for the three and six months ended June 30, 2015 compared to $1.2 million and $2.5 million for the three and six months ended June 30, 2014. Cost of energy, reflecting purchase of RECs, decreased $1.0 million for the three and six months ended June 30, 2015 compared to 2014. Revenue and margin from PNM’s energy efficiency rider decreased $0.1 million and increased $0.4 million for the three and six months ended June 30, 2015 compared to 2014. Revenues from these riders also recover incremental operating, depreciation, and interest expenses applicable to these programs.

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 $4.4 million for the three months ended June 30, 2015 compared to unrealized losses of $0.4 million for the three months ended June 30, 2014, decreased margin by $4.0 million. Unrealized losses of $6.1 million for the six months ended June 30, 2015 compared to unrealized losses of $3.2 million for the six months ended June 30, 2014, decreased margin by $2.9 million.

Reduced off-system sales and off-system purchases not passed through PNM’s FPPAC decreased revenue $1.1 million and $4.3 million and decreased cost of energy $1.4 million and $4.7 million for the three and six months ended June 30, 2015 compared to 2014. The reductions were due to less power being available for off-system sales, primarily related to SJGS.

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In June 2015, PNM negotiated new gas transportation agreements with El Paso Natural Gas, resulting in the refund of previous amounts paid under the FERC tariff and establishing new reduced rates through October 31, 2022.  The refund of previously paid gas transportation costs decreased cost of energy and increased margin $4.2 million for the three and six months ended June 30, 2015.  The newly established rates are anticipated to decrease gas transportation costs approximately $0.8 million on an annual basis.

Changes in revenue, cost of energy, and margin shown as “other” in the table above include a $1.7 million decrease in cost of energy and increase in margin related to the resolution of issues covered by the arbitration with SJCC recorded in the three months ended June 30, 2014, which did not recur in 2015. See Note 16 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K. As discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K, 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 in the three months ended June 30, 2014, which included amounts from July 1, 2013 through June 30, 2014. For the three and six months ended June 30, 2015, PNM retained revenues of $0.2 million and $0.3 million under this provision.

For the three months ended June 30, 2015, operating expenses decreased $2.7 million compared to 2014. The extension of the PVNGS Unit 1 leases on January 15, 2015, at 50% of the rental amounts that were in effect during the original lease term (Note 6), decreased operating expenses $4.1 million for the three months ended June 30, 2015 compared to 2014. Higher maintenance expenses at PVNGS, Four Corners, and natural gas-fired plants of $0.9 million, $1.3 million, and $1.4 million were partially offset by lower maintenance expenses at San Juan of $0.2 million. Lower pension expense of $0.3 million and higher capitalized administrative and general expenses of $0.7 million, due to increased capital spending, decreased operating expenses for the three months ended June 30, 2015 compared to 2014. In the three months ended June 30, 2014, PNM undertook process improvement initiatives designed to decrease future operating expenses. In connection with those initiatives, PNM incurred costs, primarily related to severances, of $1.8 million that decreased operating expenses for the three months ended June 30, 2015 compared to 2014. The termination of the lease for the 40% interest in the EIP transmission line on April 1, 2015, decreased operating expenses $0.7 million for the three months ended June 30, 2015 compared to 2014. During the three months ended June 30, 2015, PNM concluded that certain costs that were being deferred as regulatory assets were no longer probable of recovery through the ratemaking process and recorded regulatory disallowances of $1.5 million.

For the six months ended June 30, 2015, operating expenses decreased $6.4 million compared to 2014. The reduced rentals on the PVNGS Unit 1 leases decreased operating expenses $7.5 million for the six months ended June 30, 2015 compared to 2014. Higher maintenance expenses at PVNGS, Four Corners, and natural gas-fired plants of $1.6 million, $1.4 million, and $0.6 million increased operating expenses. Lower pension expense of $0.7 million and higher capitalized administrative and general expenses of $1.7 million, due to increased capital spending, reduced operating expenses for the six months ended June 30, 2015 compared to 2014. Process improvement initiatives and the termination of the EIP lease decreased operating expenses $1.8 million and $0.7 million in the six months ended June 30, 2015 compared to 2014. These decreases were partially offset by regulatory disallowances of $1.5 million and higher health care costs of $1.2 million for the six months ended June 30, 2015.

Depreciation and amortization expense increased $2.0 million and $3.3 million for the three and six months ended June 30, 2015 compared to 2014 due to additions to utility plant in service, including the addition of 23 MW of PNM-owned solar PV facilities in late 2014 and the purchase of Rio Bravo in July 2014.

Other income (deductions) increased $1.8 million and $5.6 million for the three and six months ended June 30, 2015 compared to 2014. Pre-tax gains on available-for-sale securities, reflecting performance of the NDT and the trust for coal mine reclamation, increased other income (deductions) $0.9 million and $2.3 million in the three and six months ended June 30, 2015 compared to 2014. Higher fees and taxes on the NDT decreased other income (deductions) by $1.0 million and $1.1 million in the three and six months ended June 30, 2015. Income of $1.1 million and $2.1 million from refined coal (a third-party pre-treatment process) at SJGS increased other income (deductions) for the three and six months ended June 30, 2015 compared to 2014. Higher equity AFUDC of $0.5 million and $1.2 million also increased other income (deductions) in 2015. PNM recognized a gain of $1.1 million in the three months ended June 30, 2015 from the sale to Gallup of substations and associated transmission facilities owned by PNM that had been used solely to provide service to Gallup prior to the termination of PNM’s electric service agreement with Gallup discussed above. For the three and six months ended June 30, 2015 compared to 2014, changes in the amounts of losses on retirements of PVNGS Unit 3 assets decreased other income (deductions) $0.6 million for the three months ended June 30, 2015 compared to 2014, but increased other income (deductions) $0.6 million for the six months ended June 30,

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2015. Interest income on PVNGS lessor notes decreased $0.6 million and $1.2 million during the three and six months ended June 30, 2015 compared to 2014 due to lower outstanding principal balances under the notes.

Interest charges decreased $0.3 million and $0.2 million for the three and six months ended June 30, 2015 compared to 2014 due to higher debt AFUDC, partially offset by borrowings under the $175.0 million PNM 2014 Term Loan Agreement entered into in March 2015.

As discussed in Note 13, the Company settled an IRS examination in June 2014. 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 partially offsets 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,
	2015			2014			Change			2015			2014			Change
	(In millions)
Electric operating revenues	$	77.4		$	70.5		$	6.9		$	148.4		$	136.6		$	11.8
Cost of energy	18.3			16.8			1.5			36.1			32.8			3.3
Margin	59.1			53.7			5.4			112.3			103.9			8.4
Operating expenses	20.8			20.4			0.4			42.6			41.5			1.1
Depreciation and amortization	13.6			12.0			1.6			27.0			23.8			3.2
Operating income	24.7			21.3			3.4			42.7			38.5			4.2
Other income (deductions)	0.8			0.5			0.3			2.1			0.7			1.4
Net interest charges	(6.9		)	(6.7		)	(0.2		)	(13.8		)	(13.3		)	(0.5		)
Segment earnings before income taxes	18.7			15.1			3.6			31.0			26.0			5.0
Income (taxes)	(6.8		)	(5.6		)	(1.2		)	(11.4		)	(9.6		)	(1.8		)
Segment earnings	$	11.9		$	9.5		$	2.4		$	19.6		$	16.3		$	3.3

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

	2014/2015 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	$	2.3		$	—	$	2.3		$	4.2		$	—	$	4.2
Customer usage	1.8			—		1.8			1.6			—		1.6
Customer growth	0.4			—		0.4			0.7			—		0.7
Weather	(0.3		)	—		(0.3		)	(0.2		)	—		(0.2		)
Recovery of third-party transmission costs	1.5			1.5		—			3.3			3.3		—
AMS surcharge	1.5			—		1.5			2.8			—		2.8
Other	(0.3		)	—		(0.3		)	(0.6		)	—		(0.6		)
Net change	$	6.9		$	1.5	$	5.4		$	11.8		$	3.3	$	8.4

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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,
	2015		2014		Change		2015		2014		Change
	(In millions, except consumers)
Residential	$	27.4	$	26.1	$	1.3	$	54.8	$	52.9	$	1.9
Commercial	26.5		25.3		1.2		50.1		48.4		1.7
Industrial	4.1		3.8		0.3		8.0		7.2		0.8
Other	19.4		15.3		4.1		35.5		28.1		7.4
	$	77.4	$	70.5	$	6.9	$	148.4	$	136.6	$	11.8
Average consumers (thousands) (1)	241.2		237.4		3.8		240.7		237.0		3.7

⁽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,
	2015	2014 (1)	Change		2015	2014	Change
	(Gigawatt hours)
Residential	681.2	647.0	34.2		1,345.1	1,289.1	56.0
Commercial	679.3	655.1	24.2		1,252.8	1,195.2	57.6
Industrial	728.7	669.0	59.7		1,389.2	1,317.1	72.1
Other	24.9	25.9	(1.0	)	49.6	49.4	0.2
	2,114.1	1,997.0	117.1		4,036.7	3,850.8	185.9

⁽¹⁾  The 2014 GWh amounts reflect a reclassification of 6.8 GWh and 12.5 GWh from industrial to commercial for the three and six months ended June 30, 2014 to be consistent with the current year presentation.

For the three and six months ended June 30, 2015, revenues and margin increased by $2.3 million and $4.2 million compared to 2014 due to transmission cost of service rate increases in March 2014, September 2014, and March 2015. See Note 12. TNMP’s weather normalized retail KWh sales increased 5.0% and 3.5% for the three and six months ended June 30, 2015 compared to 2014. TNMP also experienced positive year to date average customer growth of 1.5%, increasing revenues and margin by $0.4 million and $0.7 million for the three and six months ended June 30, 2015 compared to 2014. Higher weather normalized usage per customer increased revenues and margin by $1.8 million and $1.6 million for the three and six months ended June 30, 2015 compared to 2014. Milder weather decreased revenues and margins by $0.3 million and $0.2 million for the three and six months ended June 30, 2015 compared to 2014. For the three and six months ended June 30, 2015 compared to 2014, cooling degree days were 0.7% lower and 0.1% higher, and heating degree days were 41.8% and 3.4% lower. Cooling degree days have only a minor impact on the first quarter of any year, whereas heating degree days only have a minor impact on the second quarter.

Changes in 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 costs resulting from rate increases from other transmission service providers within ERCOT increased cost of energy $1.5 million and $3.3 million for the three and six months ended June 30, 2015 compared to 2014. These increases in cost of energy resulted in TNMP rate increases for the recovery of third party transmission costs increasing revenue $1.5 million and $3.3 million for the three and six months ended June 30, 2015 compared to 2014.

The AMS surcharge increased revenues and margin by $1.5 million and $2.8 million for the three and six months ended June 30, 2015 compared to 2014. Other in the table above, which includes recovery of the CTC, rate case expenses, and energy efficiency programs, was lower for the three and six months ended June 30, 2015 compared to 2014. Lower revenues were offset by decreases in operating and depreciation and amortization expenses.

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Operating expenses increased $0.4 million and $1.1 million for the three and six months ended June 30, 2015 compared to 2014. Higher employee healthcare claims of $0.7 million and $0.7 million for the three and six months ended June 30, 2015 and higher operating expenses of $0.3 million and $0.5 million for the three and six months ended June 30, 2015 associated with the AMS deployment, which are recovered through the AMS surcharge, increased operating expenses compared to 2014. Higher property taxes of $0.4 million and $0.8 million further increased operating expenses for the three and six months ending June 30, 2015. These increases were partially offset by lower property and casualty claims of $0.7 million and $0.7 million for the three and six months ended June 30, 2015 and lower incentive compensation of $0.2 million and $0.3 million for the three and six months ended June 30, 2015, which decreased operating expenses compared to 2014.

Depreciation and amortization increased $1.6 million and $3.2 million for the three and six months ended June 30, 2015 compared to 2014. Depreciation expense associated with the AMS deployment, which is recovered through the AMS surcharge, increased $0.8 million and $1.6 million for the three and six months ended June 30, 2015 compared to 2014 due to increased AMS deployment. Amortization expense associated with the CTC, which is recovered through the CTC surcharge, increased $0.2 million and $0.3 million for the three and six months ended June 30, 2015 compared to 2014. In addition, an increase in utility plant in service increased depreciation by $0.6 million and $1.3 million for the three and six months ended June 30, 2015 compared to 2014.

Other income (deductions) increased $0.3 million and $1.4 million for the three and six months ended June 30, 2015, primarily due to an increase in contributions in aid of construction.

Net interest charges increased $0.2 million and $0.5 million for the three and six months ended June 30, 2015 compared to 2014. The issuance of $80.0 million of long-term debt under the TNMP 2013 Bond Purchase Agreement on June 27, 2014 increased interest charges $0.8 million and $1.6 million for the three and six months ended June 30, 2015. This was partially offset by lower interest charges of $0.5 million and $1.0 million, for the three and six months ended June 30, 2015, due to the maturity of $50.0 million of debt under the TNMP 2011 Term Loan Agreement. See Note 9.

Corporate and Other

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

	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Change			2015			2014			Change
	(In millions)
Total revenues	$	—		$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—			—
Margin	—			—			—			—			—			—
Operating expenses	(4.0		)	(3.4		)	(0.6		)	(7.5		)	(6.6		)	(0.9		)
Depreciation and amortization	3.5			3.1			0.4			7.1			6.2			0.9
Operating income	0.5			0.2			0.3			0.5			0.4			0.1
Other income (deductions)	(0.7		)	(0.3		)	(0.4		)	(2.5		)	(1.0		)	(1.5		)
Net interest charges	(2.4		)	(3.3		)	0.9			(5.8		)	(6.4		)	0.6
Segment earnings (loss) before income taxes	(2.5		)	(3.4		)	0.9			(7.8		)	(7.0		)	(0.8		)
Income (taxes) benefit	1.0			2.8			(1.8		)	2.8			4.5			(1.7		)
Segment earnings (loss)	$	(1.6	)	$	(0.6	)	$	(1.0	)	$	(4.9	)	$	(2.5	)	$	(2.4	)

Corporate and Other operating expenses shown above are net of amounts allocated to PNM and TNMP under shared services agreements. The amounts allocated include certain expenses shown as depreciation and amortization and other income (deductions) in the table above. Operating income includes an expense of $0.2 million recorded in the three months ended March 31, 2015 related to a sales and use tax audit of a business that PNMR sold in 2011.

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Depreciation expense increased in the three and six months ended June 30, 2015 from 2014 due to additions of computer software. Substantially all depreciation and amortization expense is offset in operating expenses as a result of allocation of these costs to other business segments.

Other income (deductions) for the three months ended March 31, 2015 includes losses of $1.1 million on items included in other investments related to a former PNMR subsidiary, which ceased operations in 2008. The decrease in net interest charges is primarily related to the maturity of PNMR’s $118.8 million of 9.25% Senior Unsecured Notes, Series A on May 15, 2015, partially offset by interest on PNMR’s new $150 million PNMR 2015 Term Loan Agreement entered into on March 9, 2015. See Note 9.

During the three months ended March 31, 2015, PNMR recorded an impairment of New Mexico state net operating losses of $0.3 million (net of federal income tax benefit) that is included in income (taxes) benefit. Additionally, a tax benefit of $0.2 million and a tax expense of $0.2 million were recorded in the three months ending March 31, 2015 and March 31, 2014 resulting from refinements of the impacts of a phased-in reduction in New Mexico corporate income tax rates. In June 2014, the Company settled the IRS examination that resulted in an income tax benefit of $1.3 million in the three months ended June 30, 2014. This amount was partially offset by an additional income tax expense reflected in the PNM segment.

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR’s cash flows for the six months ended June 30, 2015 compared to June 30, 2014 are summarized as follows:

	Six Months Ended June 30,
	2015			2014			Change
	(In millions)
Net cash flows from:
Operating activities	$	109.7		$	123.8		$	(14.1	)
Investing activities	(216.5		)	(151.1		)	(65.4		)
Financing activities	84.9			36.9			48.0
Net change in cash and cash equivalents	$	(21.9	)	$	9.6		$	(31.5	)

Changes in PNMR’s cash flow from operating activities result from net earnings, adjusted for items impacting earnings that do not provide or use cash. See Results of Operations above. Certain changes in assets and liabilities resulting from normal operations also impact operating cash flows. In addition, contributions to PNMR’s pension and OPEB plans were $30.2 million higher in the six months ended June 30, 2015 than in 2014.

The changes in PNMR’s cash flows from investing activities relate primarily to an increase of $72.1 million in utility plant additions in the six months ended June 30, 2015 compared to 2014. Utility plant additions at PNM were $80.4 million higher in the six months ended June 30, 2015 compared to 2014, including increases in generation additions of $57.5 million and transmission and distribution additions of $20.8 million. The increase in generation additions at PNM includes expenditures related to environmental controls at SJGS, additional solar generation, and the La Luz peaking generating facility. TNMP utility plant additions decreased $14.2 million in the six months ended June 30, 2015 compared to 2014, including reductions in AMS additions of $8.0 million and transmission and distribution additions of $6.2 million. The decrease in additions at TNMP primarily resulted from delays in construction due to flooding and other adverse weather conditions in TNMP’s service territories. Corporate plant additions increased $5.9 million related to computer hardware and software additions. Investing activities also include principal payments received on the PVNGS lessor notes, which were $4.0 million greater in the six months ended June 30, 2015 than in 2014.

The changes in PNMR’s cash flows from financing activities include a $126.2 million increase in net short-term borrowing activity in the six months ended June 30, 2015 compared to 2014. In 2015, financing activities include $150.0 million of long-term borrowings under the PNMR 2015 Term Loan Agreement and a $25.0 million draw under the PNM Multi-draw Term Loan. The additional short-term and long-term borrowings were used to repay $118.8 million of 9.25% Senior Unsecured Notes, Series A that matured on May 15, 2015, to fund increased expenditures for utility plant additions, and for general corporate purposes. In

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2015, PNM also successfully remarketed $39.3 million of PCRBs. In 2014, long-term borrowings of $175.0 million under the PNM 2014 Term Loan Agreement were used to repay amounts under the existing $75.0 million PNM Term Loan Agreement and reduce short-term debt. In 2014, TNMP long-term borrowings of $80.0 million were used to repay amounts under the existing $50.0 million TNMP 2011 Term Loan Agreement and other short-term borrowings.

Financing Activities

See Note 6 of the Notes to Consolidated Financial Statements in the 2014 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 9, 2015, PNMR entered into the $150.0 million PNMR 2015 Term Loan Agreement between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and Administrative Agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate and must be repaid on or before March 9, 2018. The PNMR 2015 Term Loan Agreement includes customary covenants and conditions. PNMR utilized a portion of the proceeds from the PNMR 2015 Term Loan Agreement and borrowings under the PNMR Revolving Credit Facility to retire the $118.8 million of 9.25% Senior Unsecured Notes, Series A when they matured on May 15, 2015.

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 leases as debt. At June 30, 2015, interest rates on outstanding borrowings were 1.04% for the PNMR Term Loan Agreement, 1.19% for the PNMR 2015 Term Loan Agreement, 1.14% for the PNM 2014 Term Loan Agreement, and 0.77% for the PNM Multi-draw Term Loan.

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, 2015, are:

	2015		2016-2019		Total
	(In millions)
Construction expenditures	$	576.9	$	1,657.4	$	2,234.3
Dividends on PNMR common stock	63.7		254.9		318.6
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	641.1	$	1,914.4	$	2,555.5

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 $76.7 million related to environmental upgrades at SJGS to address regional haze, including amounts for the 65 MW anticipated to be owned by PNMR Development, and $212.5 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 $91.8 million, the purchase of the leased portion of the EIP on April 1, 2015, and the purchase of the assets underlying three of th

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e PVNGS Unit 2 leases at the expiration of those leases. Expenditures for the SJGS and Four Corners environmental upgrades are estimated to be $76.5 million in 2015. 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 2014 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, 2015, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements and additional term loan borrowings.

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. PNMR’s $118.8 million of 9.25% Senior Unsecured Notes, Series A matured and were repaid on May 15, 2015; $39.3 million of PNM’s PCRBs were subject to mandatory tender for remarketing on June 1, 2015 (the bonds were remarketed on that date and are next subject to mandatory tender for remarketing on June 1, 2020); the $175.0 million PNM 2014 Term Loan Agreement matures on September 4, 2015; and the $125.0 million PNM Multi-draw Term Loan matures on June 21, 2016. Note 6 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K contains information about the maturities of long-term debt. Also, the one-year $100.0 million PNMR Term Loan Agreement matures on December 21, 2015. PNMR and PNM anticipate that funds to repay the long-term debt maturities and term loans will come from entering into new arrangements similar to the existing agreements, cash and cash equivalents, borrowing under their revolving credit facilities, issuance of new long-term debt, or a combination of these sources. On June 29, 2015, PNM made a filing with the NMPRC requesting approval for the issuance of up to $300.0 million of senior unsecured notes. PNM’s filing indicated it would use the proceeds to repay the PNM 2014 Term Loan Agreement and reduce borrowings under the PNM Revolving Credit Facility and other short-term funding instruments. A NMPRC hearing on the request was held on July 20, 2015, the Hearing Examiner has issued a Recommended Decision that the request be approved, and the NMPRC is expected to rule on the request in August 2015. 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.

Liquidity

PNMR’s liquidity arrangements include the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility that both expire in October 2019 and the TNMP Revolving Credit Facility that expires in September 2018. The PNMR Revolving Credit Facility and the PNM Revolving Credit Facility provide for an additional one-year extension option for each facility, subject to approval by a majority of the lenders. 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. PNM also has 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. 

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 $7.5 million during the three month ended June 30, 2015 and from zero to $12.5 million during the six months ended June 30, 2015. Borrowings under the PNM Revolving Credit Facility ranged from zero to $36.5 million during the three months ended June 30, 2015 and from zero to $36.5 million during the six months ended June 30, 2015. Borrowings under the PNM New Mexico Credit Facility ranged from zero to $20.0 million during the three months ended June 30, 2015 and from zero to $20.0 million during the six months ended June 30, 2015. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $34.0 million during the three months ended June 30, 2015 and from zero to $34.0 million during the six months ended June 30, 2015. At June 30, 2015, the average interest rate was 1.69% under the PNMR Revolving Credit Facility, 1.44% under the PNM Revolving Credit Facility, 1.44% under the PNM New Mexico Credit Facility, and 1.19% under the TNMP Revolving Credit Facility. At June 30, 2015, TNMP had $4.1 million in borrowings from PNMR under its intercompany loan agreements.

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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 2015-2019 period. This could include debt refinancing, new debt issuances, and/or new equity.

Information concerning the credit ratings for PNMR, PNM, and TNMP was set forth under the heading Liquidity in the MD&A contained in the 2014 Annual Reports on Form 10-K. As discussed above, PNMR retired the 9.25% Senior Unsecured Notes, Series A when they matured on May 15, 2015, which results in PNMR having no senior unsecured notes outstanding. Following this repayment, Moody’s and S&P withdrew their ratings of PNMR senior unsecured debt. On June 22, 2015, Moody’s assigned an issuer rating of Baa3 to PNMR, upgraded the issuer rating of TNMP to A3 from Baa1, upgraded the senior secured debt rating of TNMP to A1from A2,and changed the outlook for PNMR, PNM, and TNMP to stable from positive. As of July 24, 2015, ratings on the Company’s securities were as follows:

	PNMR	PNM	TNMP
S&P
Corporate rating	BBB	BBB	BBB
Senior secured debt	*	*	A-
Senior unsecured debt	*	BBB	*
Preferred stock	*	BB+	*
Moody’s
Issuer rating	Baa3	Baa2	A3
Senior secured debt	*	*	A1
Senior unsecured debt	*	Baa2	*

* Not applicable

S&P has PNMR, PNM, and TNMP on positive outlook and Moody’s has all entities on a stable outlook. However, negative regulatory outcomes from the NMPRC in the SJGS BART filing, discussed in Note 11, could affect both the outlook and credit ratings. 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.

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A summary of liquidity arrangements as of July 24, 2015 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 24, 2015:
Revolving credit facility	$	—	$	43.2	$	32.0	$	75.2
PNM New Mexico Credit Facility	—		20.0		—		20.0
Letters of credit	6.8		3.2		0.1		10.1
Total short-term debt and letters of credit	6.8		66.4		32.1		105.3
Remaining availability as of July 24, 2015	$	293.2	$	383.6	$	42.9	$	719.7
Invested cash as of July 24, 2015	$	1.9	$	—	$	—	$	1.9

The above table excludes intercompany debt. As of July 24, 2015, PNM had $18.7 million and TNMP had $13.2 million in borrowings from PNMR under their intercompany loan agreements. The remaining availability under the revolving credit facilities at any point in time varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures.

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

Off-Balance Sheet Arrangements

PNMR’s off-balance sheet arrangements include PNM’s operating lease obligations for PVNGS Units 1 and 2 and, until April 1, 2015, the EIP transmission line. 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 2014 Annual Reports on Form 10-K as well as Note 5.

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 2014 Annual Reports on Form 10-K.

Contingent Provisions of Certain Obligations

As discussed in the 2014 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 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.

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Capital Structure

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

	June 30, 2015		December 31, 2014
PNMR
PNMR common equity	46.0	%	46.4	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	53.7	%	53.3	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	45.5	%	45.7	%
Preferred stock	0.4	%	0.4	%
Long-term debt	54.1	%	53.9	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	59.5	%	58.9	%
Long-term debt	40.5	%	41.1	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In 2014, GHG associated with PNM’s interests in its generating plants were approximately 6.7 million metric tons of CO₂, which comprises the vast majority of PNM’s GHG.  By comparison, the total GHG in the United States in 2013, the latest year for which EPA has published this data, were approximately 6.7 billion metric tons, of which approximately 5.5 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. In 2014, PNM added an additional 23 MW of utility-scale solar generation. PNM’s 2015 renewable energy procurement includes the construction of an additional 40 MW of PNM-owned solar PV facilities by December 31, 2015. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and began purchasing the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW, 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 geothermal 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 42 MW at June 30, 2015 and is expected to grow to over 45 MW by the end of 2015. Once fully subscribed, the distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 120 GWh. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a 2014 budget of $22.5 million and anticipated program costs of $25.8 million for the program year beginning in June 2015. PNM estimates these programs saved approximately 75 GWh of electricity in 2014. Over the next 20 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 13,000 GWh of electricity, which will avoid at least 6.5 million metric tons of CO₂ based upon projected emissions from PNM’s system-wide resources. These estimates are subject to change because of the uncertainty of many of the underlying variables, including changes in demand for electricity, and complex relationships between those variables.

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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, 2014, approximately 71.2% of PNM’s generating capacity, including resources owned, leased, and under PPAs, all of which is located within the United States, consisted of coal or gas-fired generation that produces GHG. Based on current forecasts, the Company does not expect its output of GHG from existing sources to increase significantly in the near-term. Many factors affect the amount of GHG emitted. For example, if new natural gas-fired generation resources are added to meet increased load as anticipated in PNM’s current IRP, GHG would be incrementally increased. In addition, plant performance could impact the amount of GHG emitted. If PVNGS experienced prolonged outages, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG. As described in Note 11, on February 15, 2013, PNM, NMED, and EPA agreed to pursue a strategy to address the regional haze requirements of the CAA at the coal-fired SJGS, which would include the shutdown of SJGS Units 2 and 3. The shutdown of Units 2 and 3 would result in a reduction of GHG of approximately 50% at SJGS. That agreement also contemplates that gas-fired generation would be built to partially replace the retired capacity. Although replacement power strategies include some gas-fired generation, the reduction in GHG from the retirement of the coal-fired generation would be far greater than the increase in GHG from replacement generation. In September 2013, the EIB approved a RSIP submitted by NMED that encompassed the February 15, 2013 agreement. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and became effective on November 10, 2014. Because of PNM’s dependence on fossil-fueled generation, any legislation or regulation that imposes a limit or cost on GHG could impact the cost at which electricity is produced. While PNM expects to recover any such costs through rates, the timing and outcome of proceedings for cost recovery are uncertain. In addition, to the extent that any additional costs are recovered through rates, customers may reduce their usage, relocate facilities to other areas with lower energy costs, or take other actions that ultimately will adversely impact PNM.

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

EPA Regulation

In April 2007, the United States Supreme Court held that EPA has the authority to regulate GHG under the CAA.  This decision heightened the importance of this issue for the energy industry.  In December 2009, EPA released its endangerment finding stating that the atmospheric concentrations of six key greenhouse gases (CO₂, methane, nitrous oxides, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride) endanger the public health and welfare of current and future generations. In May 2010, EPA released the final PSD and Title V Greenhouse Gas Tailoring Rule (the “Tailoring Rule”) to address GHG from stationary sources under the CAA permitting programs. The purpose of the rule was to “tailor” the applicability of two programs, PSD and Title V operating permit programs, to avoid impacting millions of small GHG emitters. The rule focused on the largest sources of GHG, including fossil-fueled electric generating units. This program covered new construction projects that emit GHG of at least 100,000 tons per year (even if PSD is not triggered for other pollutants). In addition, modifications at existing facilities that increase GHG by at least 75,000 tons per year would be subject to PSD permitting requirements, even if they did not significantly increase emissions of any other pollutant. As a result, PNM’s fossil-fueled generating plants were more likely to trigger PSD permitting requirements because of the magnitude of GHG. However as discussed below, a court case in 2014 now limits 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

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Timing and Tailoring Rules.” On October 15, 2013, the United States Supreme Court granted a petition for a Writ of Certiorari regarding the permitting of stationary sources that emit GHG. The Supreme Court limited the question that it would review to: “Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases.” Specifically, the case dealt 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.

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 rule is known as the Clean Power Plan and it 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

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from coal-fired and oil/gas-fired EGUs to natural gas combined cycle units (“NGCCs”) such that the NGCCs are at a 70% utilization rate; 3) substitution of fossil fuel generation with renewable resources and new nuclear facilities, and extension of life of about 6% of existing nuclear plants that may be retired; and 4) increases to demand-side energy efficiency programs. States would be required to develop SIPs to reach the CO₂ emission reduction goals. The SIPs would need to include enforceable CO₂ emission limits that apply to the affected EGUs within the state. EPA is proposing to allow flexibility in how each state achieves the goal including an option to use either a rate-based or mass-based standard and to develop multi-state compliance plans. State SIPs would be due thirteen months after the date that the final rule is published in the Federal Register with the possibility of a one year extension if a state needs additional time or a two year extension if states choose to enter a multi-state approach. Comments on the proposed rule were originally due on or before October 16, 2014, which was extended to December 1, 2014. PNM submitted comments by the deadline.

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

On October 28, 2014, EPA issued a notice of data availability (“NODA”) related to the proposed Clean Power Plan. The NODA provided additional information on certain issues that were consistently raised by stakeholders, including the glide path for reductions from 2020 to 2029, aspects of how the building blocks were established, and the method used to calculate the state goals. Also on October 28, 2014, EPA issued a supplemental rule proposing CO₂ emission rates for U.S. territories and areas of Indian country with existing fossil fuel-fired EGUs, as well as guidelines for plans to achieve those rates.  The supplemental proposal would apply to Four Corners, which is located on the Navajo Nation.  With respect to this plant, EPA applied the four building blocks described in its June 18, 2014 CAA Section 111(d) proposal to establish interim and final goals, expressed as CO₂ emission rates.  APS has indicated that if the rule is finalized as proposed, it is unlikely that additional emission reductions would be required as a result of the plant’s past and future actions to comply with the requirements for BART.

On November 13, 2014, EPA issued a technical support document outlining two examples of methods for translating from an emissions rate-based goal to a mass-based equivalent under the proposed Clean Power Plan. States, areas of Indian country, and territories could choose whether to meet a rate-based goal or a mass-based equivalent. If states, areas of Indian country, and territories decide to use a mass-based goal (represented as total metric tons of carbon dioxide), they would be required to demonstrate that it is equivalent to their rate-based goal.

On January 7, 2015, EPA announced its intention to propose a federal plan to meet the requirements of the section 111(d) rule, to be released in the summer of 2015 and finalized in summer 2016.  EPA also announced changes to the schedule for issuing the final GHG rule regulations for new, modified/reconstructed, and existing EGUs in "Summer 2015."  As a result, EPA indicated deadlines for compliance in subsequent years for section 111(d) actions will shift from “June” to “Summer.”  EPA initially proposed to issue a final rule for new EGUs by January 8, 2015 and had previously planned to finalize its modified/reconstructed and existing source rules in June 2015.  EPA has updated the expected deadline for the agency to issue the Federal 111(d) Plan to midsummer 2015.  EPA sent its proposed federal plan for implementation of the Clean Power Plan to the White House Office of Management and Budget (“OMB”) for review. According to OMB’s website, the proposed federal plan will be released in August of 2015 and will be finalized in August of 2016.

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

The ultimate impact of EPA’s regulation of GHG to PNM is unknown because the regulatory requirements, including NSPS requirements, are in draft form and existing power plants will be regulated by state plans that will not be finalized for several years. PNM estimates that implementation of the RSIP for BART at SJGS, which requires the installation of SNCRs on Units 1

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and 4 by the later of January 2016 or 15 months after EPA approval of the RSIP and the retirement of SJGS Units 2 and 3 by the end of 2017, should provide a significant step towards compliance with Section 111(d). PNM is currently reviewing the proposed Section 111(d) rule and is unable to predict the impact of this rule on its fossil-fueled generation.

Federal Legislation

Prospects for enactment of legislation imposing a new or enhanced regulatory program to address climate change in Congress are unlikely in 2015.  Instead, EPA continues to be the primary venue for GHG regulation in the near future, especially for coal-fired EGUs. In addition, while there are legislative proposals to limit or block implementation of the Clean Power Plan once it is finalized, enactment of these proposals is highly unlikely.

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 or tax 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.

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.  Although these prices may not reflect the costs that ultimately will be incurred, PNM is required to use these prices for purposes of its IRP.  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.

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International Accords

The United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was produced at the United Nations Conference on Environment and Development (informally known as the Earth Summit). Since the UNFCCC entered into force in March 1994, the parties, including the United States, have been meeting annually in Conferences of the Parties (“COP”) to assess progress in dealing with climate change and, beginning in the mid-1990s, to negotiate the Kyoto Protocol to establish legally binding obligations for developed countries to reduce their GHG. Specifically, the objective is to “stabilize greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.” The Company monitors the proceedings of the UNFCCC, including the annual COP meetings, to determine potential impacts to its business activities.  At the COP meeting in 2011, participating nations, including the United States, agreed that in 2015, they would sign an international treaty requiring all nations to begin reducing carbon emissions by 2020. Known as the Durban Platform for Enhanced Action, the new treaty would supplant the Kyoto Protocol, which was adopted in 1997, that targeted only industrialized nations for mandatory climate emission reductions. President Obama announced the United States’ post 2020 greenhouse gas emissions target in November of 2014, which is a commitment to cut emissions by 26%-28% from 2005 levels by the year 2025 that would put the United States on a path to economy-wide reductions of around 80% by 2050. On March 31, 2015, the United States formally submitted its intended contribution, known as the “Intended Nationally Determined Contribution (“INDCs”), to a new international climate agreement due at the December 2015 COP meeting, reflecting no change from the November 2014 announcement. Other nations are expected to release their proposed goals before the December 2015 COP meeting. To date INDCs have been submitted by 17 nations, including the United States, and the European Union. The objective of the conference is to achieve a legally binding agreement on climate from all nations. PNM will continue to monitor the United States participation in international accords. However, the Obama administration’s target for the electric utility industry will be based on EPA’s current proposals to regulate carbon and PNM believes that implementation of the RSIP for BART at SJGS should provide a significant step towards compliance with the requirements.

Transmission Issues

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

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

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

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

A final ballot for MOD-001-2 concluded on December 20, 2013 and received sufficient affirmative votes for approval. On February 10, 2014, NERC filed with FERC a petition for approval of MOD-001-2 and retirement of reliability standards MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a, and MOD-030-2. On June 19, 2014, FERC issued a NOPR to approve a new reliability standard. The MOD-001-2 standard will become effective on the first day of the calendar quarter that

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is 18 months after the date the standard is approved by FERC. MOD-001-2 will replace multiple existing reliability standards and will remove the risk of reduced TTC for PNM and other western utilities.

In July 2011, FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development for significant transmission planning related changes. In response, PNM and WestConnect (an organization of utility companies providing transmission of electricity in the western region that includes PNM) participants filed modified versions to their transmission tariff’s Attachment K (Transmission Planning Process). In March 2013, FERC issued its order regarding PNM’s and six other WestConnect FERC jurisdictional utilities’ compliance filings where FERC partially accepted many aspects of the filings. 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. On September 20, 2013, PNM and the other WestConnect FERC jurisdictional entities submitted their revised regional compliance filings to address and comply with the March 2013 FERC order.

In September 2014, FERC issued an additional order concerning the regional planning process and cost allocation in response to the September 2013 compliance filings. The FERC order required the WestConnect entities to make another compliance filing to hold a single year “abbreviated planning process for year 2015.” The order also required the entities to file the WestConnect “Planning Participation Agreement.” Of significant concern to FERC jurisdictional entities in this order was FERC’s ruling that the non-jurisdictional entities would not be required to participate in cost allocation on regional projects, which the WestConnect FERC jurisdictional entities believe does not comport with FERC’s Order 1000 position on the “cost causation principle” and could create a “free rider-ship” issue for certain participants in the planning process. Due to the cost allocation issue, FERC-regulated entities jointly filed a request for re-hearing or clarification of the FERC order in October 2014. The FERC-regulated entities filed compliance filings regarding the September 2014 FERC order in November 2014, making several adjustments to the language in their respective Attachment Ks, as well as a separate unsigned version of the proposed final version of the Planning Participation Agreement. In May 2015, FERC conditionally accepted the November 2014 filings, but denied the re-hearing request filed in October 2014. The WestConnect FERC jurisdictional entities made compliance filings regarding the May 2015 FERC order on June 16, 2015, making several adjustments to the language in their respective Attachment K.

In July 2013, the WestConnect participants submitted their cost allocation and inter-regional coordination plan between WestConnect and three other planning regions. In December 2014, FERC issued an order conditionally accepting the WestConnect compliance filing including the California Independent System Operator Corporation (“CAISO”), Northern Tier Transmission Group Applicants, and Columbia Grid (collectively the “Western Filing Parties”). The order required the Western Filing Parties to use the same method for determining the regional benefits of a proposed interregional transmission facility through revisions to the common tariff language. Without requiring modification to the common tariff language for all four Western planning regions, CAISO would tender revised tariff sheets to address the Western Filing Parties compliance condition. The WestConnect entities and the other Western Filing Parties submitted a common compliance filing on February 17, 2015, stating that CAISO had agreed to change its Open Access Transmission Tariff language and, therefore, the other entities would not have to change the common OATT language.

As of January 2015, all of the WestConnect jurisdictional entities have executed the Planning Participation Agreement and some of the non-jurisdictional entities have also signed. A 2015 study plan has been completed and committee activities are currently focused on establishing the data for the technical models, production cost models and base system to be used as the reference for the 2015 study work. WestConnect has hired a consultant to complete the single year planning study for 2015 as required in the September 2014 FERC order.

Financial Reform Legislation

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Reform Act”), enacted in July 2010, includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading facility. It also includes provisions related to swap transaction reporting and record keeping 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 has elected the end-user exception to the mandatory clearing requirement. PNM expects to be in compliance with the Dodd-Frank Reform Act and related rules within the time frames required by the CFTC. However, as a result of implementing and complying with the Dodd-Frank Reform Act and related rules, PNM’s swap activities could be subject to increased costs, including

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from higher margin requirements. 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

As discussed under Employees in Item 1. of the 2014 Annual Reports on Form 10-K, at December 31, 2014, PNM had 593 employees in its power plant and operations areas that were covered by a collective bargaining agreement with the IBEW Local 611 that was entered into in July 2012 and expired as of May 1, 2015. Negotiations for a new agreement with the IBEW began in January 2015.  Although the current agreement has expired, the agreement continues in effect during negotiations unless either the union or the Company gives a thirty days' written notice of termination. On July 22, 2015, the Company gave notice of termination, effective August 21, 2015, and plans to continue negotiations until an agreement is reached. While the Company is optimistic that a timely agreement will be reached, PNM cannot, at this time, predict the outcome of the negotiations.  PNM is currently working on contingency planning for certain scenarios that may occur as a result of negotiations and notice of termination. The wages and benefits for all PNM employees who are members of the IBEW are typically included in the rates charged to electric customers, subject to approval of the NMPRC.

On March 25, 2013, a petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for utility workers. On April 12, 2013, a second petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for meter technicians, who were not included in the original petition. Approximately 200 employees were covered by the petitions. Elections to determine whether the IBEW would represent the employees were held in May 2013.  The employees voted to unionize through both petitions and contract negotiations began. 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. As of December 31, 2014, TNMP had 195 employees represented by IBEW Local 66. In January 2015, a decertification election was held for those employees covered by the original petition. The employees voted to retain union representation. The parties reached an agreement and union members ratified the agreement on February 28, 2015. The agreement is in effect from March 9, 2015 through September 9, 2016.

See Notes 11 and 12 herein and Notes 16 and 17 of the Notes to Consolidated Financial Statements in the 2014 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, 2015, there have been no significant changes with regard to the critical accounting policies disclosed in PNMR’s, PNM’s, and TNMP’s 2014 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.

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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 the impact of federal or state regulatory action with regard to the proposed early retirement of SJGS Units 2 and 3

• Uncertainty regarding obtaining required regulatory approvals of the final restructuring, coal supply, and related agreements for SJGS, which are necessary for operational and future environmental compliance matters, in order for the agreements to become effective, as well as the closing of the sale of SJCC

• 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 currently effective coal supply agreement for SJGS

• The impacts on the electricity usage of customers and consumers due to performance of state, regional, and national economies, mandatory energy efficiency measures, weather, seasonality, alternative sources of power, and other changes in supply and demand, including the failure to maintain or replace customer contracts on favorable terms

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

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

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

• 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

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

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

• Employee workforce factors, including issues arising out of collective bargaining agreements and labor negotiations with union employees

• 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

• Changes in technology, particularly with respect to new and alternative sources of energy, smart grid technology, and cybersecurity

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

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

• Adverse outcomes of legal or regulatory proceedings, including the extent of insurance coverage

• 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 risk that FERC rulemakings may negatively impact the operation of PNM’s transmission system

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

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

• Changes in applicable accounting principles or policies

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Any material changes to risk factors occurring after the filing of PNMR’s, PNM’s, and TNMP’s 2014 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.

Our Internet addresses are:

• PNMR: www.pnmresources.com

• PNM: www.pnm.com

• TNMP: www.tnmp.com

In addition to the corporate websites, PNM has a website, www.PowerforProgress.com, dedicated to showing how it balances delivering reliable power at affordable prices and protecting the environment. This website is designed to be a resource for the facts about PNM’s operations and support efforts, including plans for building a sustainable energy future for New Mexico. 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/corporate-governance.aspx 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.

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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, 2015 and the year ended December 31, 2014, the Company had no commodity derivative instruments designated as cash flow hedging instruments.

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

	Six Months Ended
	June 30,
	2015			2014
Economic Hedges	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	9,546		$	3,273
Amount realized on contracts delivered during period	(6,509		)	1,043
Changes in fair value	382			(4,230		)
Net mark-to-market change recorded in earnings	(6,127		)	(3,187		)
Net change recorded as regulatory assets and liabilities	(22		)	(477		)
Net fair value at end of period	$	3,397		$	(391	)

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.

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Fair Value of Mark-to-Market Instruments at June 30, 2015

	Settlement Dates
	2015		2016
	(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—
Prices provided by other external sources	3,922		(525		)
Prices based on models and other valuations	—		—
Total	$	3,922	$	(525	)

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, 2015, the high, low, and average VaR amounts were $2.6 million, $0.9 million, and $1.6 million. For the year ended December 31, 2014, the high, low, and average VaR amounts were $2.1 million, $0.6 million, and $0.9 million. At June 30, 2015 and December 31, 2014, the VaR amounts for the PNM wholesale portfolio were $1.1 million and $1.3 million.

The VaR limits, which were not exceeded during the six months ended June 30, 2015 or the year ended December 31, 2014, 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 by the credit worthiness (credit rating) and concentration of credit risk for counterparties to derivative transactions. All credit exposures at June 30, 2015 will mature in less than two years.

Schedule of Credit Risk Exposure

June 30, 2015

Rating (1)	Credit Risk Exposure(2)		Number of Counter-parties >10%	Net Exposure of Counter-parties >10%
	(Dollars in thousands)
External ratings:
Investment grade	$	3,832	1	$	3,418
Non-investment grade	—		—	—
Internal ratings:
Investment grade	560		1	524
Non-investment grade	192		—	—
Total	$	4,584		$	3,942

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⁽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, 2015, PNMR held $0.2 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of June 30, 2015 was $5.4 million, which is due from a firm-requirements wholesale customer.

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 1.8%, or $40.7 million, if interest rates were to decline by 50 basis points from their levels at June 30, 2015. 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 24, 2015, PNMR, PNM, and TNMP had short-term debt outstanding of none, $43.2 million, and $32.0 million 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 borrowings of $20.0 million outstanding under its $50.0 million PNM New Mexico Credit Facility at July 24, 2015. The revolving credit facilities, the PNM New Mexico Credit Facility, the $175.0 million PNM 2014 Term Loan Agreement, the $125.0 million PNM Multi-draw Term Loan, the $100.0 million PNMR Term Loan Agreement, and the $150.0 million PNMR 2015 Term Loan Agreement bear interest at variable rates, which averaged 1.44% for the PNM Revolving Credit Facility, 1.44% for the PNM New Mexico Credit Facility, 1.19% for the TNMP Revolving Credit Facility, 1.14% for the PNM 2014 Term Loan Agreement, 0.77% for the PNM Multi-draw Term Loan, 1.04% for the PNMR Term Loan Agreement, and 1.19% for the PNMR 2015 Term Loan Agreement on July 24, 2015, 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 $253.6 million at June 30, 2015, of which 42.7% 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, 2015, the decrease in the fair value of the fixed-rate securities would be 3.4%, or $3.7 million.

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

Equity Market Risk

The investments held by PNM in trusts for decommissioning and reclamation include certain equity securities at June 30, 2015. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 55.7% of the securities held by various trusts as of June 30, 2015. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $14.1 million.

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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, 2015 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 – Citizen Suit Under the Clean Air Act

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

• Four Corners Coal Mine

• WEG v. OSM NEPA Lawsuit

• Navajo Nation Environmental Issues

• Santa Fe Generating Station

• Continuous Highwall Mining Royalty Rate

• Four Corners Severance Tax Assessment

• PVNGS Water Supply Litigation

• San Juan River Adjudication

• Rights-of-Way Matter

• Complaint Against Southwestern Public Service Company

• Navajo Nation Allottee Matters

Note 12

• PNM – 2014 Electric Rate Case

• PNM – Renewable Portfolio Standard

• PNM – Renewable Energy Rider

• PNM – Energy Efficiency and Load Management

• PNM – Integrated Resource Plan

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

• PNM – Application for Certificate of Convenience and Necessity

• PNM – Formula Transmission Rate Case

• PNM – Firm-Requirements Wholesale Customers - Navopache Electric Cooperative, Inc.

• 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.

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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, 2014.

ITEM 5. OTHER INFORMATION

Information regarding including the finalization of restructuring agreements in Form 10-Q in lieu of filing Form 8-K

Amendments to San Juan Project Participation Agreement

PNM, along with Tucson, the City of Farmington, M-S-R Public Power Agency, Incorporated County of Los Alamos, Southern California Public Power Authority, City of Anaheim, Utah Associated Municipal Power Systems, and Tri-State Generation and Transmission Association, Inc., are parties to the SJPPA. PNM, together with the other SJGS participants and PNMR Development, as of July 31, 2015, entered into the RA, the Restructuring Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement (“Restructuring Amendment”) and the Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement (“Exit Date Amendment”). These three agreements provide for the amendment of certain provisions of the SJPPA related to the restructuring of ownership in SJGS. PNMR has guaranteed the obligations of PNMR Development.

The RA addresses the transfer of ownership interests in SJGS, including the acquisition of 132 MWs and 65 MWs in Unit 4 by PNM and PNMR Development; establishes responsibility for the cost of capital improvements after January 1, 2015; provides for the payment of restructuring fees of $8.8 million and demand charges of $6.2 million by exiting SJGS participants; allocates fuel costs depending on whether costs arise under the UG-CSA or the CSA; and creates a methodology for allocating shares of environmental and certain other legacy liabilities depending on whether the liabilities are attributable to activities that occurred before or after the date certain SJGS participants exit ownership of SJGS.

The Restructuring Amendment implements certain provisions of the RA for the period January 1, 2016, through December 31, 2017, including provisions relating to fuel, demand charges, capital cost obligations and voting. The Exit Date Amendment implements provisions of the RA for the period January 1, 2018 through June 30, 2022, to reflect the exit of certain SJGS participants from SJGS and sets forth the terms under which the remaining SJGS participants will continue to operate SJGS Units 1 and 4.

The RA, the Restructuring Amendment and the Exit Date Amendment are dependent on PNM obtaining the necessary approvals from the NMPRC, the approval by FERC, and the CSA becoming effective. It is currently anticipated that the CSA and the Restructuring Amendment will become effective contemporaneously on January 1, 2016. PNM is unable to predict the ultimate outcome of this matter.

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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 February 26, 2015 (incorporated by reference to Exhibit 3.4 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2014)
3.5	PNM	Bylaws of PNM, with all amendments to and including May 31, 2002 (incorporated by reference to Exhibit 3.1.2 to PNM’s Report on Form 10-Q for the fiscal quarter ended June 30, 2002)
3.6	TNMP	Bylaws of TNMP, with all amendments to and including June 18, 2013 (incorporated by reference to Exhibit 3.6 to TNMP’s Current Report on Form 8-K filed June 20, 2013)
10.1	PNM	Letter Agreement dated May 14, 2015 between PNM and Westmoreland Coal Company
10.2	PNM	Letter Agreement Termination dated July 1, 2015 between PNM and Westmoreland Coal Company
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

111

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:	July 31, 2015	/s/ Joseph D. Tarry
		Joseph D. Tarry
		Vice President and Corporate Controller
		(Officer duly authorized to sign this report)

112

EX-10.1

PNMPatricia Vincent-Collawn

Main OfficesChairman, President & CEO

Albuquerque, NM 87158-1225        

www.pnmresources.com

Phone : 505.241.2802

Fax : 505.241.4343

May 14, 2015

Westmoreland Coal Company

9540 South Maroon Circle

Suite 200

Englewood, Colorado 80112

Attn: Keith E. Alessi

Ladies and Gentlemen:

Reference is made to the contemplated acquisition of one hundred percent (100%) of the issued and outstanding shares of San Juan Coal Company, a Delaware corporation ("SJCC") and San Juan Transportation Company, a Delaware corporation, by Westmoreland Coal Company, a Delaware corporation (“Purchaser”), from BHP Billiton New Mexico Coal, Inc., a Delaware corporation (“Seller”), pursuant to a Stock Purchase Agreement in a form to be agreed to by Purchaser and Seller (the “Purchase Agreement”), certain provisions of which it is contemplated that Public Service Company of New Mexico, a New Mexico corporation (“PNM”), shall be an intended third party beneficiary.

For good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the undersigned hereby agree as follows:

1. Purchaser and PNM hereby agree to execute and deliver (or, in the case of Purchaser, to cause SJCC to execute and deliver, as applicable), contemporaneous with the closing under the Purchase Agreement (the “Closing”), the Coal Supply Agreement, including the Guaranty substantially in the form attached thereto, the Reclamation Services Agreement and the Coal Combustion Residuals Disposal Agreement, each substantially in the form submitted by PNM to the New Mexico Public Regulation Commission on a confidential basis on May 1, 2015.

2. The obligations of the parties in paragraph 1 above are subject to satisfaction of each of the following conditions: (i) Purchaser and Seller shall have duly executed and delivered the Purchase Agreement in substantially the form submitted by PNM to the New Mexico Public Regulation Commission on a confidential basis on May 14, 2015; (ii) the Closing shall have occurred in accordance with the terms of the Purchase Agreement; (iii) any necessary regulatory approvals; and (iv) the San Juan Project Restructuring Agreement, contemplated to be entered into by and among the current and future owners of the San

Juan Generating Station, shall have become effective in accordance with the terms thereof.

3. The terms and provisions of this letter agreement shall be interpreted and construed in accordance with the laws of the State of New Mexico, without regard to conflict of law principles.

4. The parties acknowledge that money damages would not be an adequate remedy at law if any party fails to perform in any material respect any of its obligations hereunder and accordingly agree that each party, in addition to any other remedy to which it may be entitled at law or in equity, shall be entitled to specific performance of the obligations of any other party under this letter agreement and appropriate injunctive relief may be applied for and granted in connection therewith, and if any action should be brought in equity to enforce any of the provisions of this letter agreement, none of the parties shall raise the defense that there is an adequate remedy at law. No remedy shall be exclusive of any other remedy. All available remedies shall be cumulative.

5. EACH PARTY HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM (WHETHER BASED ON CONTRACT, TORT OR OTHERWISE) ARISING OUT OF OR RELATING TO, THIS LETTER AGREEMENT.

6. This letter agreement may be executed by facsimile or portable document format (.pdf) and in one or more counterparts, all of which shall be considered one and the same agreement and each of which shall be deemed an original.

{Signature Page Follows}

2

If the foregoing meets with your approval, please sign below.

Sincerely,

PUBLIC SERVICE COMPANY OF NEW MEXICO

/s/ Patricia Vincent-Collawn        

Name:     Patricia Vincent-Collawn        

Title: Chairman, President and CEO    

ACCEPTED AND AGREED TO

AS OF THE DATE FIRST WRITTEN ABOVE:

WESTMORELAND COAL COMPANY

/s/ Keith E. Alessi            

Name:     Keith E. Alessi            

Title:     CEO                    

{Signature Page to Letter Agreement re: Execution of CSA}

3

EX-10.2

Execution Version

LETTER AGREEMENT TERMINATION

July 1, 2015

Reference is made to that certain Letter Agreement, dated May 14, 2015 (the “Letter Agreement”), by and between Public Service Company of New Mexico, a New Mexico corporation (“PNM”) and Westmoreland Coal Company, a Delaware corporation (“Purchaser”), pursuant to which Purchaser and PNM agreed to execute and deliver (or, in the case of Purchaser, to cause San Juan Coal Company, a Delaware corporation ("SJCC"), to execute and deliver, as applicable), contemporaneous with the closing (the “Closing”) of the contemplated acquisition of one hundred percent (100%) of the issued and outstanding shares of SJCC and San Juan Transportation Company, a Delaware corporation, by Purchaser from BHP Billiton New Mexico Coal, Inc., a Delaware corporation (“Seller”), the Coal Supply Agreement, including the Guaranty substantially in the form attached thereto, the Reclamation Services Agreement and the Coal Combustion Residuals Disposal Agreement, each substantially in the form submitted by PNM to the New Mexico Public Regulation Commission (the “PRC”) on a confidential basis on May 1, 2015 (collectively, the “Coal Agreements”).

Pursuant to an Order Setting Further Proceedings issued by the PRC on May 27, 2015, PNM is now required to submit fully executed Coal Agreements to the PRC by July 1, 2015 rather than executing said agreements as of the Closing.

Effective as of the due execution and delivery of the Coal Agreements by PNM and Purchaser, the Letter Agreement is hereby terminated and of no further force and effect.

This Letter Agreement Termination may be executed by facsimile or portable document format (.pdf) and in one or more counterparts, all of which shall be considered one and the same agreement and each of which shall be deemed an original.

{Signature Page to Follow}

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

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: /s/ Chris M. Olson            

Name:    Chris M. Olson            

Title:    Vice President, Generation        

WESTMORELAND COAL COMPANY

By: /s/ Jennifer Grafton            

Name:    Jennifer Grafton            

Title:    Secretary, Sr. VP            

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, 2015				2014				2013				2012			2011				2010
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	59,279			$	117,337			$	118,880			$	125,379		$	122,998			$	123,633
Amortization of debt premium, discount, and expenses	1,716				4,194				3,716				4,023			3,695				4,627
Estimated interest factor of lease rental charges	1,873				4,686				5,847				5,585			6,665				6,888
Preferred dividend requirements of subsidiary	392				809				800				769			864				1,075
Total Fixed Charges	$	63,260			$	127,026			$	129,243			$	135,756		$	134,222			$	136,223
Earnings, as defined by the Securities and Exchange Commission:
Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	79,378			$	200,647			$	175,069			$	175,035		$	321,469			$	(63,379	)
(Earnings) loss of equity investee	—				—				—				—			—				15,223
Earnings (loss) from continuing operations before income taxes, non-controlling interest, and investee earnings	79,378				200,647				175,069				175,035			321,469				(48,156		)
Fixed charges as above	63,260				127,026				129,243				135,756			134,222				136,223
Interest capitalized	(3,362		)		(6,256		)		(5,209		)		(5,432		)	(2,697		)		(3,401		)
Non-controlling interest in earnings of Valencia	(7,231		)		(14,127		)		(14,521		)		(14,050		)	(14,047		)		(13,563		)
Preferred dividend requirements of subsidiary	(392		)		(809		)		(800		)		(769		)	(864		)		(1,075		)
Earnings Available for Fixed Charges	$	131,653			$	306,481			$	283,782			$	290,540		$	438,083			$	70,028
Ratio of Earnings to Fixed Charges	2.08			1	2.41			2	2.20			2	2.14			3.26			3	0.51			4
1  Earnings (loss) from continuing operations before income taxes and non-controlling interest for the six months ended June 30, 2015 includes a pre-tax loss of $1.7 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 2.11.
2  Earnings (loss) from continuing operations before income taxes and non-controlling interest for the years ended December 31, 2014 and December 31, 2013 includes pre-tax losses of $1.1 and $12.2 million due to the write-off of regulatory disallowances at PNM. If those losses were excluded, the Ratio of Earnings to Fixed Charges would have been 2.42 for 2014 and 2.29 for 2013.
3  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.
4 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, 2015				2014				2013				2012			2011				2010
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	40,695			$	79,834			$	79,769			$	82,864		$	75,217			$	73,423
Amortization of debt premium, discount and expenses	894				1,944				1,879				1,818			1,325				1,274
Estimated interest factor of lease rental charges	845				2,541				3,732				3,743			4,139				4,103
Total Fixed Charges	$	42,434			$	84,319			$	85,380			$	88,425		$	80,681			$	78,800
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes and non-controlling interest	$	56,168			$	154,086			$	151,480			$	156,314		$	105,965			$	107,288
Fixed charges as above	42,434				84,319				85,380				88,425			80,681				78,800
Non-controlling interest in earnings of Valencia	(7,231		)		(14,127		)		(14,521		)		(14,050		)	(14,047		)		(13,563		)
Interest capitalized	(2,852		)		(5,211		)		(4,420		)		(4,314		)	(1,761		)		(2,811		)
Earnings Available for Fixed Charges	$	88,519			$	219,067			$	217,919			$	226,375		$	170,838			$	169,714
Ratio of Earnings to Fixed Charges	2.09			1	2.60			2	2.55			2	2.56			2.12			3	2.15
1 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the six months ended June 30, 2015 includes a pre-tax loss $1.7 million due to the write-off of regulatory disallowances. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.13.
2 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the years ended December 31, 2014 and December 31, 2013 include pre-tax losses of $1.1 million and $12.2 million due to the write-off of regulatory disallowances. If these losses were excluded, the Ratio of Earnings to Fixed Charges would have been 2.61 for 2014 and 2.70 for 2013.
3 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, 2015			2014			2013			2012			2011				2010
Fixed charges, as defined by the Securities and Exchange Commission:
Interest expensed and capitalized	$	12,901		$	24,941		$	24,481		$	26,233		$	27,914			$	28,632
Amortization of debt premium, discount and expenses	528			1,195			1,159			1,493			1,679				2,683
Estimated interest factor of lease rental charges	715			1,311			1,241			956			1,202				1,246
Total Fixed Charges	$	14,144		$	27,447		$	26,881		$	28,682		$	30,795			$	32,561
Earnings, as defined by the Securities and Exchange Commission:
Earnings from continuing operations before income taxes	$	30,963		$	60,330		$	46,711		$	42,099		$	36,138			$	26,026
Fixed charges as above	14,144			27,447			26,881			28,682			30,795				32,561
Interest capitalized	(297		)	(609		)	(361		)	(706		)	(593		)		(158		)
Earnings Available for Fixed Charges	$	44,810		$	87,168		$	73,231		$	70,075		$	66,340			$	58,429
Ratio of Earnings to Fixed Charges	3.17			3.18			2.72			2.44			2.15			1	1.79
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:	July 31, 2015	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:	July 31, 2015	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:	July 31, 2015	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:	July 31, 2015	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:	July 31, 2015	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, Charles N. Eldred, 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:	July 31, 2015	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer
			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, 2015, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on July 31, 2015 (“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:	July 31, 2015	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, 2015, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on July 31, 2015 (“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:	July 31, 2015	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, 2015, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on July 31, 2015 (“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:	July 31, 2015	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chief Executive Officer
			Texas-New Mexico Power Company
		By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer

XML

Variable Interest Entities (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2015 USD ($) MW	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($) MW	Jun. 30, 2014 USD ($)	Dec. 31, 2014 USD ($)	Oct. 08, 2013 USD ($)
Variable Interest Entity, Statement Of Operation [Abstract]
Earnings attributable to non-controlling interest	$ 3,850,000	$ 3,908,000	$ 7,231,000	$ 7,439,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	410,065,000		410,065,000		$ 432,817,000
Total assets	5,927,018,000	5,604,192,000	5,927,018,000	5,604,192,000	5,829,325,000
Current liabilities	701,104,000		701,104,000		704,282,000
Owners’ equity – non-controlling interest	73,163,000		73,163,000		73,546,000
Net earnings	31,673,000	29,141,000	$ 46,013,000	41,609,000
Public Service Company of New Mexico [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Renewal Options After Original Lease Term (in years)			2 years
Operating Leases, Extended Lease Term Option (in years)			6 years
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Future Minimum Payments Due, Next Six Months	18,400,000		$ 18,400,000		26,000,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Property Lease Guarantee [Member] | Maximum [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Loss Contingency, Range of Possible Loss, Portion Not Accrued	217,300,000.0		217,300,000.0
Valencia [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Long Term Contract For Purchase of Electric Power Fixed Costs	4,800,000	4,800,000	9,600,000	9,600,000
Long Term Contract For Purchase of Electric Power Variable Charges	500,000	500,000	600,000	700,000
Variable Interest Entity, Statement Of Operation [Abstract]
Operating revenues	5,251,000	5,307,000	10,155,000	10,238,000
Operating expenses	(1,401,000)	(1,399,000)	(2,924,000)	(2,799,000)
Earnings attributable to non-controlling interest	3,850,000	3,908,000	7,231,000	7,439,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	3,284,000		3,284,000		2,513,000
Net property, plant, and equipment	71,180,000		71,180,000		72,321,000
Total assets	74,464,000		74,464,000		74,834,000
Current liabilities	1,301,000		1,301,000		1,288,000
Owners’ equity – non-controlling interest	$ 73,163,000		$ 73,163,000		$ 73,546,000
Long term contract option to purchase, ownership percentage	50.00%
Long term contract option to purchase, purchase price - percentage of adjusted NBV	50.00%
Long term contract option to purchase, purchase price - percentage of FMV	50.00%
Long term contract option to purchase, number of days to set FMV	60 days
Long term contract option to purchase, estimated purchase price						$ 85,000,000
Long term contract option to purchase, approximate approval period	15 months
Valencia [Member] | Public Service Company of New Mexico [Member] | Purchased Through May 30, 2028 [Member]
Variable Interest Entity [Line Items]
Number of mega watts purchased (in megawatts) | MW	158		158
Variable Interest Entity, Not Primary Beneficiary [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating leases, future minimum payments due, renewal term	$ 150,500,000		$ 150,500,000
Delta [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Long Term Contract For Purchase of Electric Power Fixed Costs		1,600,000		3,200,000
Long Term Contract For Purchase of Electric Power Variable Charges		300,000		500,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Period of Long Term Contract For Purchase of Electric Power Fixed Costs	20 years
Delta [Member] | Public Service Company of New Mexico [Member] | Delta [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Revenues		2,500,000		4,300,000
Net earnings		$ 300,000		$ 600,000

XML

Commitments and Contingencies - Stipulation Filed with the NMPRC (Details) $ in Millions	Apr. 08, 2015 USD ($) MW	Oct. 01, 2014 USD ($) $ / kw MW	Dec. 20, 2013 USD ($) $ / kw MW	Jun. 30, 2015 USD ($) MW	May. 19, 2015 MW	Jan. 15, 2015 MW	Jun. 26, 2014 MW
San Juan Generating Station Unit 4 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | MW		132	78	132	132		132
Public Utilities, Estimated rate base value at 1/1/2018		$ 26.0
Public Utilities, Ownership in Megawatts PNM has agreed not to obtain | MW						65
San Juan Generating Station Unit 4 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR Hearing Examiner Recommended Denial [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | MW	132
Period of time to accept or reject modifications in recommendation	7 days
San Juan Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Proposed reduction in carrying value		26.0
Public Utilities, Estimated unrecoverable increase in operations and maintenance		20.0
San Juan Generating Station Unit 3 [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Estimated pre-tax regulatory disallowance	$ 155.0	70.0
San Juan Generating Station Unit 3 [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Estimated pre-tax regulatory disallowance	145.0	$ 60.0
San Juan Generating Station Units 2 and 3 [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Net book value				$ 278.0
San Juan Generating Station Units 2 and 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Recovery Percentage of Estimated undepreciated value at 12/31/17		50.00%
Public Utilities, Estimated undepreciated value at 12/31/17	$ 128.5	$ 231.0
Public Utilities, Requested Time Period to Recover Retired Units NBV		20 years	20 years
Public Utilities, Write-off Percentage of Estimated undepreciated value at 12/31/17	50.00%	50.00%
Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Net book value				$ 147.0
Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Estimated rate base value at 1/1/2018		$ 221.1
Public Utilities, Proposed value per Kilowatt effective January 1, 2018 | $ / kw		1,650
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation | MW				134
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation | MW		134	134
Public Utilities, Proposed value per Kilowatt effective January 1, 2018 | $ / kw			2,500
Public Utilities, Percentage capacity factor 7-year performance threshold		75.00%
Public Utilities, Period over which to measure capacity performance		7 years
San Juan Generating Station Units 1 and 4 [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Installation Capital Costs		$ 90.6	$ 82.0

XML

Stock-Based Compensation (Details) - USD ($)	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 7,800,000		$ 6,500,000
Options, Outstanding at end of period, No intrinsic value	245,950
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options, Outstanding at beginning of period, Shares	920,505
Options, Granted, Shares	0
Options, Exercised, Shares	(210,945)
Options, Forfeited, Shares	(1,000)
Options, Expired, Shares	(66,201)
Options, Outstanding at end of period, Shares	642,359
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Options, Outstanding at beginning of period, Weighted-Average Exercise Price (in dollars per share)	$ 20.39
Options, Granted, Weighted-Average Exercise Price (in dollars per share)	0.00
Options, Exercised, Weighted-Average Exercise Price (in dollars per share)	20.07
Options, Forfeited, Weighted-Average Exercise Price (in dollars per share)	30.50
Options, Expired, Weighted-Average Exercise Price (in dollars per share)	27.90
Options, Outstanding at end of period, Weighted-Average Exercise Price (in dollars per share)	19.51
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value of options granted	$ 0.00	$ 0.00
Total fair value of options that vested (in thousands)	$ 0	$ 0
Total intrinsic value of options exercised (in thousands)	$ 1,759,000	$ 1,779,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected quarterly dividends per share	$ 0.200	$ 0.185
Risk-free interest rate	0.92%	0.62%
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Restricted Stock, Outstanding at beginning of period, Shares	258,770
Restricted Stock, Outstanding at end of period, Shares	250,695
Restricted Stock, Granted, Shares	340,020
Restricted Stock, Exercised, Shares	(348,095)
Restricted Stock, Forfeited, Shares	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Restricted Stock, Outstanding at beginning of period, Weighted-Average Grant Date Fair Value (in dollars per share)	$ 22.31
Restricted Stock, Granted, Weighted-Average Grant Date Fair Value (in dollars per share)	20.34	$ 21.27
Restricted Stock, Exercised, Weighted-Average Grant Date Fair Value (in dollars per share)	18.59
Restricted Stock, Forfeited, Weighted-Average Grant Date Fair Value (in dollars per share)	0.00
Restricted Stock, Outstanding at end of period, Weighted-Average Grant Date Fair Value (in dollars per share)	24.82
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value	$ 20.34	$ 21.27
Total fair value of restricted shares that vested (in thousands)	$ 6,470,000	$ 4,854,000
Market-Based Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Risk-free interest rate	1.00%	0.64%
Dividend yield	2.87%	2.82%
Expected volatility	18.73%	25.11%
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options, Outstanding at end of period, Aggregate Intrinsic Value	$ 4,700,000
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years)	2 years 7 months 13 days
Executive [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Included from Shares Outstanding, Number	179,845
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	180,970
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Two	165,628
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Three	168,258
Chairman, President, and Chief Executive Officer [Member] | Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return	135,000
Chairman, President, and Chief Executive Officer [Member] | Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 and she remains an employee [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return	35,000
Chairman, President, and Chief Executive Officer [Member] | Achieves a specific performance target by the end of 2019 and she remains an employee [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return	53,859
Chairman, President, and Chief Executive Officer [Member] | Achieves a specific performance target by the end of 2017 and she remains an employee [Member] [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return	17,953
Executive Vice President and Chief Financial Officer [Member] | Achieved performance target for 2015 and 2016 [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, Purchase price of common stock	$ 100,000
Executive Vice President and Chief Financial Officer [Member] | Achieved performance target for 2015, 2016 and 2017 [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, Purchase price of common stock	$ 275,000
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%

XML

Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Service billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 21,340	$ 22,190	$ 44,067	$ 43,256
Service billings [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	6,591	6,963	13,680	14,224
Service billings [Member] | PNM to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	184	133	288	242
Service billings [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	0	0
Interest charges [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	22	0	28	54
Interest charges [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	54	83	133	180
Interest charges [Member] | PNM to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	26	25	55	51
Income tax sharing payments [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	1,450	0
Income tax sharing payments [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 0	$ 0	$ 0	$ 0

XML

Commitments and Contingencies - SJGS Matters (Details)	Jul. 31, 2015 MW	Jun. 30, 2015 MW	May. 19, 2015 MW	Apr. 08, 2015 MW	Jan. 22, 2015 USD ($)	Jan. 07, 2015 MW	Oct. 01, 2014 MW	Jun. 27, 2014 USD ($)	Jun. 26, 2014 USD ($) MW	Mar. 11, 2014 USD ($)	Dec. 20, 2013 MW
Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Unsubscribed Ownership in Megawatts						65
Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Jointly Owned Utility Plan, Proposed Proportionate Ownership Share									64.50%
Public Service Company of New Mexico [Member] | San Juan Generating Station Units 1 and 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Jointly Owned Utility Plan, Proposed Proportionate Ownership Share									58.70%
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 3 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Percentage of ownership held by exiting owners		50.00%
Public Utilities, Ownership Percentage		50.00%
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Percentage of ownership held by exiting owners		38.80%
Public Utilities, Ownership Percentage		38.50%
Public Utilities, Additional Ownership To Be Obtained, in Megawatts		132	132				132		132		78
Public Utilities, Costs to obtain additional ownership | $									$ 0
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Requested Expenditure, Installation Capital Costs | $					$ 76,600,000					$ 1,900,000
Requested Additional Expenditure, Installation Capital Costs | $								$ 6,400,000
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR Hearing Examiner Recommended Denial [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Additional Ownership To Be Obtained, in Megawatts				132
PNMR Development [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Potential Acquisition of Ownership in Megawatts		65	65			65
Subsequent Event [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR Hearing Examiner Recommended Denial [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Additional Ownership To Be Obtained, in Megawatts	132

XML

Fair Value of Derivative and Other Financial Instruments - Debt Maturities (Details) $ in Thousands	Jun. 30, 2015 USD ($)
PNMR and PNM [Member]
Available-for-sale Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Available-for-sale debt securities, Within 1 year	$ 4,656
Available-for-sale debt securities, After 1 year through 5 years	21,533
Available-for-sale debt securities, After 5 years through 10 years	22,577
Available-for-sale debt securities, After 10 years through 15 years	10,137
Available-for-sale debt securities, After 15 years through 20 years	10,727
Available-for-sale debt securities, After 20 years	38,658
Available-for-sale debt securities	108,288
PNM Resources [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Held-to-maturity debt securities, Due within 1 year	17,230
Held-to-maturity debt securities, After 1 year through 5 years	639
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	17,869
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	17,230
Held-to-maturity debt securities, After 1 year through 5 years	0
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	$ 17,230

XML

Regulatory and Rate Matters (Tables)

6 Months Ended

Jun. 30, 2015

Regulated Operations [Abstract]

Schedule of Rate Increases for Transmission Costs

The following sets forth TNMP’s most recent interim transmission cost rate increases:

Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 17, 2013	$	18.1	$	2.8
March 13, 2014	18.2		2.9
September 8, 2014	25.2		4.2
March 16, 2015	27.1		4.4

XML

Commitments and Contingencies - National Ambient Air Quality Standards (Details) - Public Service Company of New Mexico [Member]	Mar. 02, 2015 lb / MMBTU T	Jun. 30, 2015 opp	Nov. 25, 2014 opp	Nov. 08, 2013 lb / MMBTU	Jan. 31, 2010 opp
National Ambient Air Quality Standards, 2015 EPA Legal Settlement [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Period of time to act on settlement	16 months
Public Utilities, Emissions Tons of SO2 per year | T	16,000
San Juan Generating Station [Member] | National Ambient Air Quality Standards [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Revised SO2 Emissions Agreed Upon | lb / MMBTU				0.10
Minimum [Member] | National Ambient Air Quality Standards, 2015 EPA Legal Settlement [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Emissions Tons of SO2 per year | T	2,600
Public Utilities, 1-hour SO2 Emissions Rate | lb / MMBTU	0.45
Minimum [Member] | San Juan Generating Station And Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Proposed Government Standard Emission Limit			65		60
Maximum [Member] | San Juan Generating Station And Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Proposed Government Standard Emission Limit			70		70
Public Utilities, Government Standard Emission Limit		75

XML

Goodwill (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Apr. 01, 2015	Dec. 31, 2014	Jun. 30, 2014	Apr. 01, 2014	Apr. 01, 2012
Goodwill [Line Items]
Goodwill	$ 278,297		$ 278,297	$ 278,297
Public Service Company of New Mexico [Member]
Goodwill [Line Items]
Goodwill		$ 51,600			$ 51,600
Percentage of fair value in excess of carrying amount		25.00%			30.00%
Texas-New Mexico Power Company [Member]
Goodwill [Line Items]
Goodwill						$ 226,700
Percentage of fair value in excess of carrying amount						26.00%

XML

Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2015

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,
	2015		2014		2015		2014
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	31,673	$	29,141	$	46,013	$	41,609
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	99		110		105		146
Average Shares – Basic	79,753		79,764		79,759		79,800
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	380		464		384		508
Average Shares – Diluted	80,133		80,228		80,143		80,308
Net Earnings Per Share of Common Stock:
Basic	$	0.40	$	0.37	$	0.58	$	0.52
Diluted	$	0.40	$	0.36	$	0.57	$	0.52

⁽¹⁾  Excludes the effect of out-of-the-money options for 245,950 shares of common stock at June 30, 2015.

XML

Financing - Short-term Debt (Details) - USD ($)	Jul. 24, 2015	Jun. 30, 2015	Dec. 31, 2014	Jan. 08, 2014
Short-term Debt [Line Items]
Short-term debt		$ 187,600,000	$ 105,600,000
Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 719,700,000
PNMR Term Loan Agreement [Member]
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate		1.04%
Short-term debt		$ 100,000,000	100,000,000
PNM Resources [Member] | Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	293,200,000
Restricted Cash and Investments	1,900,000
Public Service Company of New Mexico [Member] | Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	353,600,000
Restricted Cash and Investments	0
Public Service Company of New Mexico [Member] | Subsequent Event [Member] | Affiliated Entity [Member]
Short-term Debt [Line Items]
Short-term debt – affiliate	18,700,000
Public Service Company of New Mexico [Member] | Local Lines of Credit [Member]
Short-term Debt [Line Items]
Debt Instruments, NMPRC Approved credit facility				$ 50,000,000
Short-term debt		20,000,000	0
Public Service Company of New Mexico [Member] | Local Lines of Credit [Member] | Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	30,000,000
Texas-New Mexico Power Company [Member] | Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	42,900,000
Restricted Cash and Investments	0
Texas-New Mexico Power Company [Member] | Subsequent Event [Member] | Affiliated Entity [Member]
Short-term Debt [Line Items]
Short-term debt – affiliate	$ 13,200,000
Texas-New Mexico Power Company [Member] | Intercompany loan agreements [Member]
Short-term Debt [Line Items]
Short-term debt - affiliate		4,100,000
Revolving Credit Facility [Member] | PNM Resources [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 300,000,000.0
Short-term Debt, Weighted Average Interest Rate		1.69%
Short-term debt		$ 7,500,000	600,000
Revolving Credit Facility [Member] | Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 400,000,000.0
Short-term Debt, Weighted Average Interest Rate		1.44%
Short-term debt		$ 31,100,000	0
Revolving Credit Facility [Member] | Texas-New Mexico Power Company [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 75,000,000.0
Short-term Debt, Weighted Average Interest Rate		1.19%
Short-term debt		$ 29,000,000	$ 5,000,000
Revolving Credit Facility [Member] | Texas-New Mexico Power Company [Member] | First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]
Short-term Debt [Line Items]
Debt Instrument, Collateral Amount		$ 75,000,000
Local Lines of Credit [Member] | Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Short-term Debt, Weighted Average Interest Rate		1.44%

XML

Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - PNMR and PNM [Member] - Commodity Contract [Member] - Fair Value Hedging [Member] - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 904	$ (267)	$ 382	$ (4,230)
Electric operating revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	1,003	(324)	531	(4,475)
Cost of energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ (99)	$ 57	$ (149)	$ 245

XML

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	$ 352,887	$ 346,160	$ 685,755	$ 675,057
Cost of energy	114,038	109,419	229,683	222,033
Margin	238,849	236,741	456,072	453,024
Other operating expenses	120,386	123,282	242,578	248,845
Depreciation and amortization	46,049	42,163	91,510	84,130
Operating income	72,414	71,296	121,984	120,049
Interest income	1,941	2,040	3,691	4,158
Other income (deductions)	7,566	5,710	12,889	6,924
Net interest charges	(28,913)	(29,972)	(59,186)	(59,506)
Earnings before Income Taxes	53,008	49,074	79,378	71,625
Income taxes (benefit)	17,353	15,893	25,870	22,313
Net Earnings	35,655	33,181	53,508	49,312
Valencia non-controlling interest	(3,850)	(3,908)	(7,231)	(7,439)
Subsidiary preferred stock dividends	(132)	(132)	(264)	(264)
Net Earnings Available for PNM Common Stock	31,673	29,141	46,013	41,609
Total Assets	5,927,018	5,604,192	5,927,018	5,604,192	$ 5,829,325
Goodwill	278,297	278,297	278,297	278,297	278,297
Public Service Company of New Mexico [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	275,450	275,704	537,390	538,441
Cost of energy	95,728	92,642	193,594	189,268
Margin	179,722	183,062	343,796	349,173
Other operating expenses	103,541	106,233	207,557	213,957
Depreciation and amortization	29,002	27,023	57,405	54,105
Operating income	47,179	49,806	78,834	81,111
Interest income	1,946	2,065	3,717	4,193
Other income (deductions)	7,446	5,512	13,257	7,180
Net interest charges	(19,681)	(20,023)	(39,640)	(39,835)
Earnings before Income Taxes	36,890	37,360	56,168	52,649
Income taxes (benefit)	11,527	13,106	17,302	17,189
Net Earnings	25,363	24,254	38,866	35,460
Valencia non-controlling interest	(3,850)	(3,908)	(7,231)	(7,439)
Subsidiary preferred stock dividends	(132)	(132)	(264)	(264)
Net Earnings Available for PNM Common Stock	21,381	20,214	31,371	27,757
Total Assets	4,544,279	4,290,529	4,544,279	4,290,529	4,473,652
Goodwill	51,632	51,632	51,632	51,632	51,632
Texas-New Mexico Power Company [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	77,437	70,456	148,365	136,616
Cost of energy	18,310	16,777	36,089	32,765
Margin	59,127	53,679	112,276	103,851
Other operating expenses	20,807	20,411	42,567	41,481
Depreciation and amortization	13,591	12,003	27,049	23,844
Operating income	24,729	21,265	42,660	38,526
Interest income	0	0	0	0
Other income (deductions)	793	514	2,084	702
Net interest charges	(6,856)	(6,655)	(13,781)	(13,252)
Earnings before Income Taxes	18,666	15,124	30,963	25,976
Income taxes (benefit)	6,801	5,590	11,404	9,640
Net Earnings	11,865	9,534	19,559	16,336
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings Available for PNM Common Stock	11,865	9,534	19,559	16,336
Total Assets	1,268,862	1,208,517	1,268,862	1,208,517	1,240,241
Goodwill	226,665	226,665	226,665	226,665	$ 226,665
Corporate and Other [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	0	0	0	0
Cost of energy	0	0	0	0
Margin	0	0	0	0
Other operating expenses	(3,962)	(3,362)	(7,546)	(6,593)
Depreciation and amortization	3,456	3,137	7,056	6,181
Operating income	506	225	490	412
Interest income	(5)	(25)	(26)	(35)
Other income (deductions)	(673)	(316)	(2,452)	(958)
Net interest charges	(2,376)	(3,294)	(5,765)	(6,419)
Earnings before Income Taxes	(2,548)	(3,410)	(7,753)	(7,000)
Income taxes (benefit)	(975)	(2,803)	(2,836)	(4,516)
Net Earnings	(1,573)	(607)	(4,917)	(2,484)
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings Available for PNM Common Stock	(1,573)	(607)	(4,917)	(2,484)
Total Assets	113,877	105,146	113,877	105,146
Goodwill	$ 0	$ 0	$ 0	$ 0

XML

Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - Palo Verde Nuclear Generating Station [Member] - Public Service Company of New Mexico [Member] - USD ($)		1 Months Ended	3 Months Ended
	Oct. 07, 2014	Mar. 31, 2015	Jun. 30, 2014	Jun. 30, 2015	Dec. 31, 2014
Nuclear Spent Fuel And Waste Disposal [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss				$ 58,000,000
Revised Annual Fee, Nuclear Waste Disposal			$ 0
Nuclear Spent Fuel And Waste Disposal [Member] | Other Deferred Credits [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency Accrual				$ 12,500,000	$ 12,300,000
Nuclear Spent Fuel And Waste Disposal [Member] | Settled Litigation [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Lawsuit settlement, third party receipt	$ 57,400,000
PNMs share of lawsuit settlement, third party receipt	$ 5,900,000
Department of energy, spent nuclear fuel removal July 2011 - June 2014 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Lawsuit settlement, third party receipt		$ 42,000,000
PNMs share of third party settlement claim		4,300,000
Litigation Settlement, Portion credited to customers		$ 3,100,000

XML

Regulatory and Rate Matters - TNMP Narrative (Details) - Texas-New Mexico Power Company [Member]	1 Months Ended
	Jul. 30, 2011 USD ($)	Jul. 24, 2015 customer	Jun. 30, 2015 USD ($) customer
Advanced Meter System Deployment and Surcharge Request [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Deployment Costs	$ 113,400,000
Public Utilities, Collection of Deployment Costs Through Surcharge Period	12 years
Public Utilities, Completion Period of Advanced Meter Deployment	5 years
Public Utilities, Non-standard metering service cost total to be borne by opt-out customers			$ 200,000
Public Utilities, Non-standard metering 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 | customer			1,081
Advanced Meter System Deployment and Surcharge Request [Member] | Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Current number of customers that have elected non-standard meter service | customer		96
Advanced Meter System Deployment and Surcharge Request [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Non-standard metering service cost initial fee range			$ 63.97
Advanced Meter System Deployment and Surcharge Request [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Non-standard metering service cost initial fee range			168.61
Energy Efficiency [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved 2014 Program Implementation Costs			5,600,000
Public Utilities, Unapproved 2015 Program Implementation Costs, Bonus			700,000
Public Utilities, Unapproved 2015 Program Implementation Costs			5,700,000
Public Utilities, Approved 2014 Incentive Portion of Program Implementation Costs			1,500,000
Public Utilities, Requested 2016 Program Implementation Costs			5,900,000
Public Utilities, Unapproved 2016 Program Implementation Costs, Bonus			$ 600,000

XML

Regulatory and Rate Matters - Electric Rate Case (Details) - 2014 Electric Rate Case [Member] - Public Service Company of New Mexico [Member] $ in Millions		6 Months Ended
	May. 27, 2015	Jun. 30, 2015 USD ($)	Jun. 25, 2015
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 107.4
Public Utilities, Requested Return on Equity, Percentage		10.50%
Public Utilities, Average customer bill increase percentage		7.69%
Public Utilities, Percentage of requested rate increase pertaining to infrastructure investments		92.00%
Future test year period, Number of days following the filing of application for rate increase	45 days	13 months
Public Utilities, Number of other utilities filing appeals			2
Public Utilities, Number of other parties filing cross appeals			1

XML

Fair Value of Derivative and Other Financial Instruments - Recurring (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 253,550	$ 250,145
PNM Resources [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,205,847	2,173,117
Investment in PVNGS lessor notes	17,230	32,836
Other investments	1,146	2,375
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	507	639
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	2,205,847	2,173,117
Investment in PVNGS lessor notes	0	0
Other investments	0	0
PNM Resources [Member] | Fair Value, Inputs, 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	17,230	32,836
Other investments	639	1,736
Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,644,887	1,624,222
Investment in PVNGS lessor notes	17,230	32,836
Other investments	265	397
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	265	397
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	1,644,887	1,624,222
Investment in PVNGS lessor notes	0	0
Other investments	0	0
Public Service Company of New Mexico [Member] | Fair Value, Inputs, 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	17,230	32,836
Other investments	0	0
Texas-New Mexico Power Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	410,961	427,356
Other investments	242	242
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	242	242
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	410,961	427,356
Other investments	0	0
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	0	0
Reported Value Measurement [Member] | PNM Resources [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,031,158	1,975,090
Investment in PVNGS lessor notes	16,568	31,232
Other investments	507	1,762
Reported Value Measurement [Member] | Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,515,676	1,490,657
Investment in PVNGS lessor notes	16,568	31,232
Other investments	265	397
Reported Value Measurement [Member] | Texas-New Mexico Power Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	365,482	365,667
Other investments	242	242
Cash and equivalents [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,940	8,276
Domestic value [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	45,750	45,340
Domestic growth [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	78,515	74,053
International and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,057	16,599
U.S. Government [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	30,421	22,563
Municipals [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	58,986	68,973
Corporate and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	18,881	14,341
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	253,550	250,145
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	178,512	169,919
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	75,038	80,226
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	4,550	11,232
Commodity derivative liabilities	(1,153)	(1,686)
Commodity derivative instruments, Net	3,397	9,546
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	0	0
Commodity derivative liabilities	0	0
Commodity derivative instruments, Net	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	4,550	11,232
Commodity derivative liabilities	(1,153)	(1,686)
Commodity derivative instruments, Net	3,397	9,546
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,940	8,276
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,940	8,276
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	45,750	45,340
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	45,750	45,340
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	78,515	74,053
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	78,515	74,053
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,057	16,599
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,057	16,599
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	30,421	22,563
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	29,131	20,808
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,290	1,755
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	58,986	68,973
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	58,986	68,973
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	18,881	14,341
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	4,119	4,843
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 14,762	$ 9,498

XML

Significant Accounting Policies and Responsibility for Financial Statements

6 Months Ended

Jun. 30, 2015

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, 2015 and December 31, 2014 and the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2015 and 2014, and the consolidated cash flows for the six months ended June 30, 2015 and 2014. 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 2014 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2015 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 2014 Annual Reports on Form 10-K.

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

Principles of Consolidation

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

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. 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 $0.200 per share in July 2015 and $0.185 in July 2014, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

PNM and TNMP declared cash dividends on common stock to PNMR of $20.0 million and $7.7 million in June 2015 that were paid on July 1, 2015. PNM declared no dividends on its common stock in the six months ended June 30, 2014. TNMP declared and paid cash dividends of $6.8 million in the six months ended June 30, 2014.

New Accounting Pronouncements

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

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

On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard was to be 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. On July 9, 2015, the FASB approved a one-year deferral in the effective date of ASU 2014-09, with early adoption as of the original effective date permitted. 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 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

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

Accounting Standards Update 2015-03 - Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs

On April 7, 2015, the FASB issued ASU No. 2015-03, which requires that issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction of the carrying amount of that debt and not as an asset. The ASU is effective for the Company for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is evaluating the impacts of the ASU. Currently, unamortized debt issuance costs that would be reclassified are included in other deferred charges on the Condensed Consolidated Balance Sheets and, at June 30, 2015, amounted to $11.8 million for PNMR, $7.5 million for PNM, and $4.2 million for TNMP.

Accounting Standards Update 2015-07 - Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)

On May 1, 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The new standard is effective for reporting periods beginning after December 31, 2016, with early adoption permitted. Once adopted, the update is required to be applied on a retrospective basis for all periods presented. The Company is in the process of analyzing this new standard; however, it is not expected to have a material impact on the financial statements other than the disclosure and presentation of certain investments of the Company’s employee benefit plans that are measured using the net asset value practical expedient.

XML

Regulatory and Rate Matters - Renewable Portfolio Standard and Energy Rider (Details) - Public Service Company of New Mexico [Member]	3 Months Ended		6 Months Ended	12 Months Ended
	Jun. 30, 2015 USD ($) MWh MW	Dec. 31, 2014 USD ($)	Jun. 30, 2015 USD ($) MW	Dec. 31, 2014 USD ($) $ / MWh	Dec. 31, 2013 USD ($)	Feb. 27, 2015 USD ($)
Renewable Portfolio Standard [Member] | Required Percentage by 2011 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales	10.00%		10.00%
Renewable Portfolio Standard [Member] | Required Percentage by 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales	15.00%		15.00%
Renewable Portfolio Standard [Member] | Required Percentage by 2020 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales	20.00%		20.00%
Renewable Portfolio Standard [Member] | Minimum [Member] | Wind Energy [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Diversification	30.00%		30.00%
Renewable Portfolio Standard [Member] | Minimum [Member] | Solar Energy [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Diversification	20.00%		20.00%
Renewable Portfolio Standard [Member] | Minimum [Member] | Renewable Technologies [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Diversification	5.00%		5.00%
Renewable Portfolio Standard [Member] | Minimum [Member] | Distributed Generation [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Diversification	3.00%		3.00%
Renewable Portfolio Standard [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Reasonable Cost Threshold	3.00%		3.00%
2014 Wind generated Renewable Energy Credits [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Mega Watt Hours of Wind Generation | MWh	50,000
Renewable Portfolio Standard 2014 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity | MW	23		23
Public Utilities, Estimated Cost of Mega Watts of Solar Photovoltaic Capacity			$ 46,700,000
Public Utilities, Wind Capacity Planned Purchase Agreement Term			20 years
Public Utilities, Number of Mega Watts of Wind Energy Capacity | MW			102
Public Utilities, First Year Cost of Wind Capacity Planned Purchase Agreement			$ 5,800,000.0
Public Utilities, Final Cost of Solar Photovoltaic Capacity					$ 46,500,000
Public Utilities, Cost of renewable resources procured	$ 100,000	$ 100,000
2015 Wind generated Renewable Energy Credits [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Mega Watt Hours of Wind Generation | MWh	120,000
Renewable Portfolio Standard 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity | MW	40		40
Public Utilities, Estimated Cost of Mega Watts of Solar Photovoltaic Capacity			$ 79,300,000
Public Utilities, Approved Revised cost per MWh for additional necessary procurements to comply with RPS | $ / MWh				3.00
Renewable Energy Rider [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revenue from Renewable energy rider				$ 34,300,000
Renewable Energy Rider [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013			10.50%		10.50%
Public Utilities, Annual Revenue To be Collected Under 2015 Rider Rate	$ 44,700,000		$ 44,700,000
Public Utilities, Revised Annual Revenue To be Collected Under 2015 Rider Rate						$ 43,000,000
Public Utilities, Annual Revenue To be Collected Under 2016 Rider Rate	$ 42,400,000

XML

Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) - PNMR and PNM [Member] $ in Thousands	Jun. 30, 2015 USD ($) dth mwh	Dec. 31, 2014 USD ($) dth mwh
Derivative [Line Items]
Contractual Liability	$ 1,143	$ 1,686
Existing Cash Collateral	0	0
Net Exposure	$ 83	$ 167
Gas related contract [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Long Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh) | dth	865,000	650,000
Power related contract [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Short Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh) | mwh	968,305	1,919,000

XML

Fair Value of Derivative and Other Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2015

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, 2015			December 31, 2014
PNMR and PNM	(In thousands)
Current assets	$	4,550		$	11,232
	4,550			11,232
Current liabilities	(1,153		)	(1,209		)
Long-term liabilities	—			(477		)
	(1,153		)	(1,686		)
Net	$	3,397		$	9,546

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,
	2015			2014			2015			2014
PNMR and PNM	(In thousands)
Electric operating revenues	$	1,003		$	(324	)	$	531		$	(4,475	)
Cost of energy	(99		)	57			(149		)	245
Total gain (loss)	$	904		$	(267	)	$	382		$	(4,230	)

Schedule of Notional Amounts of Outstanding Derivative Positions

The table below presents PNMR’s and PNM’s net buy (sell) volume positions:

	Economic Hedges
	MMBTU	MWh
PNMR and PNM
June 30, 2015	865,000	(968,305	)
December 31, 2014	650,000	(1,919,000	)

Schedule of Collateral Related to Derivative

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)
PNMR and PNM
June 30, 2015	$	1,143	$	—	$	83
December 31, 2014	$	1,686	$	—	$	167

Available-for-sale Securities

At June 30, 2015 and December 31, 2014, the fair value of available-for-sale securities included $247.8 million and $244.6 million for the NDT and $5.7 million and $5.5 million for the mine reclamation trust. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	June 30, 2015				December 31, 2014
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,940	$	—	$	8,276
Equity securities:
Domestic value	15,015		45,750		17,418		45,340
Domestic growth	19,850		78,515		21,354		74,053
International and other	1,147		17,057		156		16,599
Fixed income securities:
U.S. Government	276		30,421		903		22,563
Municipals	3,098		58,986		5,851		68,973
Corporate and other	411		18,881		666		14,341
	$	39,797	$	253,550	$	46,348	$	250,145

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. Gross realized losses shown below exclude the change in realized impairment losses of $(1.2) million and $(0.8) million for the three and six months ended June 30, 2015 and $0.1 million and $0.6 million for the three and six months ended June 30, 2014.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands)
Proceeds from sales	$	62,670		$	30,316		$	94,522		$	53,119
Gross realized gains	$	8,329		$	5,364		$	13,465		$	8,482
Gross realized (losses)	$	(1,578	)	$	(755	)	$	(3,119	)	$	(1,794	)

Investments Classified by Contractual Maturity Date

At June 30, 2015, 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	$	4,656	$	17,230	$	17,230
After 1 year through 5 years	21,533		639		—
After 5 years through 10 years	22,577		—		—
After 10 years through 15 years	10,137		—		—
After 15 years through 20 years	10,727		—		—
After 20 years	38,658		—		—
	$	108,288	$	17,869	$	17,230

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, 2015 and December 31, 2014 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, 2015	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,940		$	3,940	$	—
Equity securities:
Domestic value	45,750			45,750		—
Domestic growth	78,515			78,515		—
International and other	17,057			17,057		—
Fixed income securities:
U.S. Government	30,421			29,131		1,290
Municipals	58,986			—		58,986
Corporate and other	18,881			4,119		14,762
	$	253,550		$	178,512	$	75,038
Commodity derivative assets	$	4,550		$	—	$	4,550
Commodity derivative liabilities	(1,153		)	—		(1,153		)
Net	$	3,397		$	—	$	3,397
December 31, 2014
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	8,276		$	8,276	$	—
Equity securities:
Domestic value	45,340			45,340		—
Domestic growth	74,053			74,053		—
International and other	16,599			16,599		—
Fixed income securities:
U.S. Government	22,563			20,808		1,755
Municipals	68,973			—		68,973
Corporate and other	14,341			4,843		9,498
	$	250,145		$	169,919	$	80,226
Commodity derivative assets	$	11,232		$	—	$	11,232
Commodity derivative liabilities	(1,686		)	—		(1,686		)
Net	$	9,546		$	—	$	9,546

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, 2015	(In thousands)
PNMR
Long-term debt	$	2,031,158	$	2,205,847	$	—	$	2,205,847	$	—
Investment in PVNGS lessor notes	$	16,568	$	17,230	$	—	$	—	$	17,230
Other investments	$	507	$	1,146	$	507	$	—	$	639
PNM
Long-term debt	$	1,515,676	$	1,644,887	$	—	$	1,644,887	$	—
Investment in PVNGS lessor notes	$	16,568	$	17,230	$	—	$	—	$	17,230
Other investments	$	265	$	265	$	265	$	—	$	—
TNMP
Long-term debt	$	365,482	$	410,961	$	—	$	410,961	$	—
Other investments	$	242	$	242	$	242	$	—	$	—
December 31, 2014
PNMR
Long-term debt	$	1,975,090	$	2,173,117	$	—	$	2,173,117	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	1,762	$	2,375	$	639	$	—	$	1,736
PNM
Long-term debt	$	1,490,657	$	1,624,222	$	—	$	1,624,222	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	397	$	397	$	397	$	—	$	—
TNMP
Long-term debt	$	365,667	$	427,356	$	—	$	427,356	$	—
Other investments	$	242	$	242	$	242	$	—	$	—

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Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2015

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,
	2015			2014			2015			2014
	(In thousands)
Operating revenues	$	5,251		$	5,307		$	10,155		$	10,238
Operating expenses	(1,401		)	(1,399		)	(2,924		)	(2,799		)
Earnings attributable to non-controlling interest	$	3,850		$	3,908		$	7,231		$	7,439

Financial Position

	June 30,		December 31,
	2015		2014
	(In thousands)
Current assets	$	3,284	$	2,513
Net property, plant, and equipment	71,180		72,321
Total assets	74,464		74,834
Current liabilities	1,301		1,288
Owners’ equity – non-controlling interest	$	73,163	$	73,546

XML

Commitments and Contingencies - Four Corners (Details) $ in Millions	Jun. 30, 2015 USD ($) lbsofnox / mmbtu	Dec. 31, 2013	Aug. 06, 2012 compliance_alternative
Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Jointly Owned Utility Plant, Sale of Ownership Percentage		48.00%
Clean Air Act Related to Post Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Compliance alternatives			2
Public Utilities, Plant Requirement to Meet NOx emissions Limit | lbsofnox / mmbtu	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%
Loss Contingency, Estimate of Possible Loss | $	$ 91.8
Clean Air Act Related to Post Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners Units 4 and 5 (Coal) [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Ownership Percentage	13.00%

XML

Fair Value of Derivative and Other Financial Instruments - Sale of Power (Details)	Jun. 30, 2015 MW	Dec. 31, 2014 $ / MWh
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation | MW	134
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative, Average Forward Price		37
Palo Verde Nuclear Generating Station [Member] | Firm Contract [Member] | Public Service Company of New Mexico [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Percentage of Electric Power Plant Output Sold for 2014 and 2015	100.00%

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Stock-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

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,
Restricted Stock	2015		2014
Weighted-average grant date fair value	$	20.34	$	21.27
Total fair value of restricted shares that vested (in thousands)	$	6,470	$	4,854
Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	—
Total intrinsic value of options exercised (in thousands)	$	1,759	$	1,779

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	2015			2014
Expected quarterly dividends per share	$	0.200		$	0.185
Risk-free interest rate	0.92		%	0.62		%
Market-Based Shares
Dividend yield	2.87		%	2.82		%
Expected volatility	18.73		%	25.11		%
Risk-free interest rate	1.00		%	0.64		%

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, 2015:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2014	258,770		$	22.31	920,505		$	20.39
Granted	340,020		$	20.34	—		$	—
Exercised	(348,095	)	$	18.59	(210,945	)	$	20.07
Forfeited	—		$	—	(1,000	)	$	30.50
Expired	—		$	—	(66,201	)	$	27.90
Outstanding at June 30, 2015	250,695		$	24.82	642,359		$	19.51

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Financing (Tables)

6 Months Ended

Jun. 30, 2015

Debt Disclosure [Abstract]

Schedule of Short-term Debt

Short-term debt outstanding consisted of:

	June 30,		December 31,
Short-term Debt	2015		2014
	(In thousands)
PNM:
Revolving credit facility	$	31,100	$	—
PNM New Mexico Credit Facility	20,000		—
TNMP – Revolving credit facility	29,000		5,000
PNMR:
Revolving credit facility	7,500		600
PNMR Term Loan Agreement	100,000		100,000
	$	187,600	$	105,600

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Condensed Consolidated Statement of Changes in Equity - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands	Total	Parent [Member]	Common Stock [Member]	AOCI [Member]	Retained Earnings [Member]	Non-controlling Interest in Valencia [Member]	Public Service Company of New Mexico [Member]	Public Service Company of New Mexico [Member] Parent [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] 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] Retained Earnings [Member]
Beginning balance at Dec. 31, 2014	$ 1,795,092	$ 1,721,546	$ 1,173,845	$ (61,755)	$ 609,456	$ 73,546	$ 1,336,402	$ 1,262,856	$ 1,061,776	$ (61,755)	$ 262,835	$ 73,546
Beginning balance TNMP at Dec. 31, 2014	1,721,546						1,262,856						$ 524,665	$ 64	$ 404,166	$ 120,435
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from stock option exercise	7,347	7,347	7,347
Awards of common stock	(18,814)	(18,814)	(18,814)
Excess tax (shortfall) from stock-based payment arrangements	(136)	(136)	(136)
Stock based compensation expense	2,761	2,761	2,761
Valencia’s transactions with its owner	(7,614)					(7,614)	(7,614)					(7,614)
Net Earnings	53,508	46,277			46,277	7,231	38,866	31,635		0	31,635	$ 7,231	19,559
Net earnings	46,013						31,635						19,559			19,559
Subsidiary preferred stock dividends	(264)	(264)			(264)
Total other comprehensive income	(2,070)	(2,070)		(2,070)			(2,070)	(2,070)		(2,070)	0		0
Dividends declared on common stock	(15,931)	(15,931)			(15,931)		(20,000)	(20,000)		0	(20,000)		(7,694)			(7,694)
Dividends declared on preferred stock							(264)	(264)		0	(264)
Ending balance at Jun. 30, 2015	1,813,879	$ 1,740,716	$ 1,165,003	$ (63,825)	$ 639,538	$ 73,163	1,345,320	$ 1,272,157	$ 1,061,776	$ (63,825)	$ 274,206	$ 73,163
Ending balance TNMP at Jun. 30, 2015	$ 1,740,716						$ 1,272,157						$ 536,530	$ 64	$ 404,166	$ 132,300

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Pension and Other Postretirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2015

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
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	51		$	45		$	—	$	—
Interest cost	7,064			7,541			1,023			1,159			190		205
Expected return on plan assets	(9,831		)	(9,511		)	(1,403		)	(1,410		)	—		—
Amortization of net (gain) loss	3,705			3,255			491			556			81		52
Amortization of prior service cost	(241		)	(241		)	(160		)	(336		)	—		—
Net periodic benefit cost	$	697		$	1,044		$	2		$	14		$	271	$	257
	Six Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	102		$	91		$	—	$	—
Interest cost	14,127			15,082			2,045			2,315			380		411
Expected return on plan assets	(19,662		)	(19,022		)	(2,805		)	(2,819		)	—		—
Amortization of net (gain) loss	7,410			6,510			983			1,113			162		105
Amortization of prior service cost	(483		)	(483		)	(321		)	(672		)	—		—
Net periodic benefit cost	$	1,392		$	2,087		$	4		$	28		$	542	$	516

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
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	62		$	59		$	—	$	—
Interest cost	761			798			152			155			9		10
Expected return on plan assets	(1,105		)	(1,132		)	(130		)	(133		)	—		—
Amortization of net (gain) loss	195			166			—			(31		)	1		—
Amortization of prior service cost	—			—			—			8			—		—
Net Periodic Benefit Cost (Income)	$	(149	)	$	(168	)	$	84		$	58		$	10	$	10
	Six Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	124		$	119		$	—	$	—
Interest cost	1,521			1,597			304			309			18		20
Expected return on plan assets	(2,210		)	(2,263		)	(260		)	(267		)	—		—
Amortization of net (gain) loss	391			333			—			(61		)	2		—
Amortization of prior service cost	—			—			—			16			—		—
Net Periodic Benefit Cost (Income)	$	(298	)	$	(333	)	$	168		$	116		$	20	$	20

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Lease Commitments (Details) $ in Millions	6 Months Ended
	Jun. 30, 2015 USD ($) MW	Jan. 14, 2016 USD ($)	Jun. 01, 2014 USD ($)	May. 01, 2014 MW
Public Service Company of New Mexico [Member]
Operating Leased Assets [Line Items]
Public Utilities, Option to Purchase Leased Capacity At Fair Value	$ 7.7
Public Service Company of New Mexico [Member] | TGP Granada, LLC and its affiliate Complaint [Member]
Operating Leased Assets [Line Items]
Public Utilities, Lease ownership percentage in EIP	60.00%
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 31.2494 MW [Member]
Operating Leased Assets [Line Items]
Purchase Price of Leased Asset to be paid	$ 78.1
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases [Member]
Operating Leased Assets [Line Items]
Leased Capacity to be Purchased | MW				32.76
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases, January 15, 2016 [Member]
Operating Leased Assets [Line Items]
Leased Capacity to be Purchased | MW	31.25
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]
Operating Leased Assets [Line Items]
Purchase Price of Leased Asset to be paid	$ 85.2
Early Purchase Price of Leased Asset, Period 1			$ 79.9
Early Purchase Price of Leased Asset	83.4
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Maximum [Member]
Operating Leased Assets [Line Items]
Additional consideration for early purchase of leased asset, Period 1			$ 5.8
Additional consideration for early purchase of leased asset, Period 2	$ 2.8
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Subsequent Event [Member]
Operating Leased Assets [Line Items]
Purchase Price of Leased Asset, Period 3		$ 85.2
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Subsequent Event [Member] | Minimum [Member]
Operating Leased Assets [Line Items]
Additional consideration for early purchase of leased asset effective June 1, 2014		$ 1.2
Tortoise Capital Resources Corporation [Member] | TGP Granada, LLC and its affiliate Complaint [Member]
Operating Leased Assets [Line Items]
Public Utilities, Lease ownership percentage in EIP	40.00%

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Commitments and Contingencies - The Clean Air Act (Details) $ in Millions	Oct. 01, 2014 USD ($) $ / kw MW	Dec. 20, 2013 USD ($) $ / kw MW	Jun. 30, 2015 USD ($) T / yr state MW	May. 19, 2015 MW	Jun. 26, 2014 MW	Oct. 31, 2012 USD ($)
Clean Air Act related to Regional Haze [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of States To Address Regional Haze | state			50
Public Utilities, Potential to emit tons per year of visibility impairing pollution, maximum | T / yr			250
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share						46.30%
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Overall Reduction Of Ownership, in Megawatts | MW		340
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SCR [Member] [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Total Capital Cost If Requirement Occurred						$ 824.0
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Installation Capital Costs						85.0
Estimated Portion of Total Capital Costs if Requirement Occured						105.0
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SCR [Member] [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Total Capital Cost If Requirement Occurred						910.0
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Installation Capital Costs						90.0
Estimated Portion of Total Capital Costs if Requirement Occured						$ 110.0
San Juan Generating Station Units 2 and 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Requested Time Period to Recover Retired Units NBV	20 years	20 years
Public Utilities, Newly Identified Replacement Gas-fired Generation, in Megawatts, December2013 | MW		177
Public Utilities, Newly Identified Replacement Solar Generation, in Megawatts, December2013 | MW		40
Public Utilities, Newly Identified Replacement Gas-fired Generation, in Megawatts | MW			187
San Juan Generating Station Units 2 and 3 [Member] | Pnm Electric [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated cost of replacing gas fired peaking capacity due to retirement of SJGS units			$ 212.5
Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Proposed value per Kilowatt effective January 1, 2018 | $ / kw	1,650
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation | MW			134
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation | MW	134	134
Public Utilities, Proposed value per Kilowatt effective January 1, 2018 | $ / kw		2,500
San Juan Generating Station Units 1 and 4 [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Installation Capital Costs	$ 90.6	$ 82.0
San Juan Generating Station Unit 4 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | MW	132	78	132	132	132
San Juan Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Ownership To Be Exchanged, in Megawatts | MW		78

XML

Condensed Consolidated Statements of Earnings - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Electric Operating Revenues	$ 352,887	$ 346,160	$ 685,755	$ 675,057
Operating Expenses:
Cost of energy	114,038	109,419	229,683	222,033
Administrative and general	39,928	45,235	83,787	89,093
Energy production costs	44,790	45,846	87,459	93,134
Regulatory disallowances	1,529	0	1,744	0
Depreciation and amortization	46,049	42,163	91,510	84,130
Transmission and distribution costs	16,868	16,068	33,354	32,974
Taxes other than income taxes	17,271	16,133	36,234	33,644
Total operating expenses	280,473	274,864	563,771	555,008
Operating income	72,414	71,296	121,984	120,049
Other Income and Deductions:
Interest income	1,941	2,040	3,691	4,158
Gains on available-for-sale securities	5,556	4,699	9,580	7,272
Other income	5,717	3,180	10,679	4,754
Other (deductions)	(3,707)	(2,169)	(7,370)	(5,102)
Net other income and deductions	9,507	7,750	16,580	11,082
Interest Charges	28,913	29,972	59,186	59,506
Earnings before Income Taxes	53,008	49,074	79,378	71,625
Income Taxes	17,353	15,893	25,870	22,313
Net Earnings	35,655	33,181	53,508	49,312
(Earnings) Attributable to Valencia Non-controlling Interest	(3,850)	(3,908)	(7,231)	(7,439)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Net Earnings Attributable to PNMR	31,673	29,141	46,013	41,609
Net Earnings Available for PNM Common Stock	$ 31,673	$ 29,141	$ 46,013	$ 41,609
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)	$ 0.40	$ 0.37	$ 0.58	$ 0.52
Diluted (dollars per share)	0.40	0.36	0.57	0.52
Dividends Declared per Common Share (dollars per share)	$ 0.200	$ 0.185	$ 0.400	$ 0.37
Public Service Company of New Mexico [Member]
Electric Operating Revenues	$ 275,450	$ 275,704	$ 537,390	$ 538,441
Operating Expenses:
Cost of energy	95,728	92,642	193,594	189,268
Administrative and general	36,956	40,603	76,524	79,213
Energy production costs	44,790	45,846	87,459	93,134
Regulatory disallowances	1,529	0	1,744	0
Depreciation and amortization	29,002	27,023	57,405	54,105
Transmission and distribution costs	10,272	10,183	21,040	21,510
Taxes other than income taxes	9,994	9,601	20,790	20,100
Total operating expenses	228,271	225,898	458,556	457,330
Operating income	47,179	49,806	78,834	81,111
Other Income and Deductions:
Interest income	1,946	2,065	3,717	4,193
Gains on available-for-sale securities	5,556	4,699	9,580	7,272
Other income	4,901	2,443	8,292	3,555
Other (deductions)	(3,011)	(1,630)	(4,615)	(3,647)
Net other income and deductions	9,392	7,577	16,974	11,373
Interest Charges	19,681	20,023	39,640	39,835
Earnings before Income Taxes	36,890	37,360	56,168	52,649
Income Taxes	11,527	13,106	17,302	17,189
Net Earnings	25,363	24,254	38,866	35,460
(Earnings) Attributable to Valencia Non-controlling Interest	(3,850)	(3,908)	(7,231)	(7,439)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Net Earnings Attributable to PNMR	21,513	20,346	31,635	28,021
Net Earnings Available for PNM Common Stock	21,381	20,214	31,371	27,757
Texas-New Mexico Power Company [Member]
Electric Operating Revenues	77,437	70,456	148,365	136,616
Operating Expenses:
Cost of energy	18,310	16,777	36,089	32,765
Administrative and general	8,042	8,768	17,875	18,609
Depreciation and amortization	13,591	12,003	27,049	23,844
Transmission and distribution costs	6,596	5,885	12,314	11,464
Taxes other than income taxes	6,169	5,758	12,378	11,408
Total operating expenses	52,708	49,191	105,705	98,090
Operating income	24,729	21,265	42,660	38,526
Other Income and Deductions:
Interest income	0	0	0	0
Other income	792	586	2,332	1,006
Other (deductions)	1	(72)	(248)	(304)
Net other income and deductions	793	514	2,084	702
Interest Charges	6,856	6,655	13,781	13,252
Earnings before Income Taxes	18,666	15,124	30,963	25,976
Income Taxes	6,801	5,590	11,404	9,640
Net Earnings	11,865	9,534	19,559	16,336
(Earnings) Attributable to Valencia Non-controlling Interest	0	0	0	0
Preferred Stock Dividend Requirements of Subsidiary	0	0	0	0
Net Earnings Attributable to PNMR	11,865	9,534	19,559	16,336
Net Earnings Available for PNM Common Stock	$ 11,865	$ 9,534	$ 19,559	$ 16,336

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Fair Value of Derivative and Other Financial Instruments - Available for Sale Securities (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Schedule of Available-for-sale Securities [Line Items]
Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net, Available-for-sale Securities	$ 1,200	$ (100)	$ 800	$ (600)
PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	253,550		253,550		$ 250,145
Available-for-sale Securities, Gross Unrealized Gain	39,797		39,797		46,348
Proceeds from sales	62,670	30,316	94,522	53,119
Gross realized gains	8,329	5,364	13,465	8,482
Gross realized (losses)	(1,578)	$ (755)	(3,119)	$ (1,794)
PNMR and PNM [Member] | Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	3,940		3,940		8,276
Available-for-sale Securities, Gross Unrealized Gain	0		0		0
PNMR and PNM [Member] | Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	45,750		45,750		45,340
Available-for-sale Securities, Gross Unrealized Gain	15,015		15,015		17,418
PNMR and PNM [Member] | Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	78,515		78,515		74,053
Available-for-sale Securities, Gross Unrealized Gain	19,850		19,850		21,354
PNMR and PNM [Member] | International and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	17,057		17,057		16,599
Available-for-sale Securities, Gross Unrealized Gain	1,147		1,147		156
PNMR and PNM [Member] | U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	30,421		30,421		22,563
Available-for-sale Securities, Gross Unrealized Gain	276		276		903
PNMR and PNM [Member] | Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	58,986		58,986		68,973
Available-for-sale Securities, Gross Unrealized Gain	3,098		3,098		5,851
PNMR and PNM [Member] | Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	18,881		18,881		14,341
Available-for-sale Securities, Gross Unrealized Gain	411		411		666
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	253,550		253,550		250,145
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Nuclear Decommissioning Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	247,800		247,800		244,600
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Mine Reclamation Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	5,700		5,700		5,500
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	3,940		3,940		8,276
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	45,750		45,750		45,340
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	78,515		78,515		74,053
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | International and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	17,057		17,057		16,599
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	30,421		30,421		22,563
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	58,986		58,986		68,973
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	$ 18,881		$ 18,881		$ 14,341

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Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current Assets:
Cash and cash equivalents	$ 6,404	$ 28,274
Accounts receivable, net of allowance for uncollectible accounts	94,703	87,038
Unbilled revenues	75,527	63,719
Other receivables	30,027	39,857
Materials, supplies, and fuel stock	71,913	63,628
Regulatory assets	23,142	47,855
Commodity derivative instruments	4,550	11,232
Income taxes receivable	5,934	6,360
Current portion of accumulated deferred income taxes	26,383	26,383
Other current assets	71,482	58,471
Total current assets	410,065	432,817
Other Property and Investments:
Investment in PVNGS lessor notes	0	9,538
Available-for-sale securities	253,550	250,145
Other investments	507	1,762
Non-utility property	3,404	3,406
Total other property and investments	257,461	264,851
Utility Plant:
Plant in service and plant held for future use	6,085,078	5,941,581
Less accumulated depreciation and amortization	2,017,711	1,939,760
Net plant in service and plant held for future use	4,067,367	4,001,821
Construction work in progress	261,049	190,389
Nuclear fuel, net of accumulated amortization	81,275	77,796
Net utility plant	4,409,691	4,270,006
Deferred Charges and Other Assets:
Regulatory assets	474,426	491,007
Goodwill	278,297	278,297
Other deferred charges	97,078	92,347
Total deferred charges and other assets	849,801	861,651
Total assets	5,927,018	5,829,325
Current Liabilities:
Short-term debt	187,600	105,600
Current installments of long-term debt	300,000	333,066
Accounts payable	88,509	110,029
Customer deposits	12,711	12,555
Accrued interest and taxes	49,452	53,863
Regulatory liabilities	2,202	1,703
Commodity derivative instruments	1,153	1,209
Dividends declared	132	16,063
Other current liabilities	59,345	70,194
Total current liabilities	701,104	704,282
Long-term Debt	1,731,158	1,642,024
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	918,519	891,111
Regulatory liabilities	470,558	466,143
Asset retirement obligations	108,406	104,170
Accrued pension liability and postretirement benefit cost	70,583	110,738
Commodity derivative instruments	0	477
Other deferred credits	101,282	103,759
Total deferred credits and other liabilities	1,669,348	1,676,398
Total liabilities	$ 4,101,610	$ 4,022,704
Commitments and Contingencies (See Note 11)
Cumulative preferred stock of subsidiary without mandatory redemption requirements	$ 11,529	$ 11,529
Company common stockholders’ equity:
Common stock outstanding	1,165,003	1,173,845
Accumulated other comprehensive income (loss), net of income taxes	(63,825)	(61,755)
Retained earnings	639,538	609,456
Total Company common stockholders' equity	1,740,716	1,721,546
Non-controlling interest in Valencia	73,163	73,546
Total equity	1,813,879	1,795,092
Total liabilities and stockholders' equity	5,927,018	5,829,325
Public Service Company of New Mexico [Member]
Current Assets:
Cash and cash equivalents	3,550	25,480
Accounts receivable, net of allowance for uncollectible accounts	70,342	67,622
Unbilled revenues	65,277	54,140
Other receivables	29,751	37,622
Affiliate receivables	10,746	8,853
Materials, supplies, and fuel stock	68,719	60,859
Regulatory assets	17,699	43,980
Commodity derivative instruments	4,550	11,232
Income taxes receivable	5,816	6,105
Current portion of accumulated deferred income taxes	12,418	12,418
Other current assets	64,082	53,095
Total current assets	352,950	381,406
Other Property and Investments:
Investment in PVNGS lessor notes	0	9,538
Available-for-sale securities	253,550	250,145
Other investments	265	397
Non-utility property	96	96
Total other property and investments	253,911	260,176
Utility Plant:
Plant in service and plant held for future use	4,698,267	4,581,066
Less accumulated depreciation and amortization	1,542,034	1,486,406
Net plant in service and plant held for future use	3,156,233	3,094,660
Construction work in progress	217,860	169,673
Nuclear fuel, net of accumulated amortization	81,275	77,796
Net utility plant	3,455,368	3,342,129
Deferred Charges and Other Assets:
Regulatory assets	344,472	357,045
Goodwill	51,632	51,632
Other deferred charges	85,946	81,264
Total deferred charges and other assets	482,050	489,941
Total assets	4,544,279	4,473,652
Current Liabilities:
Short-term debt	51,100	0
Current installments of long-term debt	300,000	214,300
Accounts payable	67,553	86,055
Affiliate payables	20,991	18,232
Customer deposits	12,711	12,555
Accrued interest and taxes	29,817	29,298
Regulatory liabilities	2,202	1,703
Commodity derivative instruments	1,153	1,209
Dividends declared	20,132	132
Other current liabilities	45,276	52,053
Total current liabilities	550,935	415,537
Long-term Debt	1,215,676	1,276,357
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	734,871	715,814
Regulatory liabilities	431,552	425,481
Asset retirement obligations	107,377	103,182
Accrued pension liability and postretirement benefit cost	63,340	102,850
Commodity derivative instruments	0	477
Other deferred credits	83,679	86,023
Total deferred credits and other liabilities	1,420,819	1,433,827
Total liabilities	$ 3,187,430	$ 3,125,721
Commitments and Contingencies (See Note 11)
Cumulative preferred stock of subsidiary without mandatory redemption requirements	$ 11,529	$ 11,529
Company common stockholders’ equity:
Common stock outstanding	1,061,776	1,061,776
Accumulated other comprehensive income (loss), net of income taxes	(63,825)	(61,755)
Retained earnings	274,206	262,835
Total Company common stockholders' equity	1,272,157	1,262,856
Non-controlling interest in Valencia	73,163	73,546
Total equity	1,345,320	1,336,402
Total liabilities and stockholders' equity	4,544,279	4,473,652
Texas-New Mexico Power Company [Member]
Current Assets:
Cash and cash equivalents	1	1
Accounts receivable, net of allowance for uncollectible accounts	24,361	19,416
Unbilled revenues	10,250	9,579
Other receivables	712	2,063
Materials, supplies, and fuel stock	3,194	2,769
Regulatory assets	5,443	3,875
Current portion of accumulated deferred income taxes	6,398	6,398
Other current assets	2,117	938
Total current assets	52,476	45,039
Other Property and Investments:
Other investments	242	242
Non-utility property	2,240	2,240
Total other property and investments	2,482	2,482
Utility Plant:
Plant in service and plant held for future use	1,207,232	1,182,112
Less accumulated depreciation and amortization	391,169	375,407
Net plant in service and plant held for future use	816,063	806,705
Construction work in progress	32,149	16,538
Net utility plant	848,212	823,243
Deferred Charges and Other Assets:
Regulatory assets	129,954	133,962
Goodwill	226,665	226,665
Other deferred charges	9,073	8,850
Total deferred charges and other assets	365,692	369,477
Total assets	1,268,862	1,240,241
Current Liabilities:
Short-term debt	29,000	5,000
Short-term debt – affiliate	4,100	22,700
Accounts payable	12,277	14,203
Affiliate payables	4,123	2,469
Accrued interest and taxes	28,401	28,574
Dividends declared	7,694	0
Other current liabilities	3,116	2,271
Total current liabilities	88,711	75,217
Long-term Debt	365,482	365,667
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	224,260	217,945
Regulatory liabilities	39,006	40,662
Asset retirement obligations	884	848
Accrued pension liability and postretirement benefit cost	7,243	7,888
Other deferred credits	6,746	7,349
Total deferred credits and other liabilities	278,139	274,692
Total liabilities	$ 732,332	$ 715,576
Commitments and Contingencies (See Note 11)
Company common stockholders’ equity:
Common stock outstanding	$ 64	$ 64
Paid-in-capital	404,166	404,166
Retained earnings	132,300	120,435
Total Company common stockholders' equity	536,530	524,665
Total liabilities and stockholders' equity	$ 1,268,862	$ 1,240,241

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Commitments and Contingencies - Coal Supply (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	$ 71,482	$ 58,471
Public Service Company of New Mexico [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory Assets	100,000
Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Annual Funding		1,000	$ 300	$ 3,500
Public Service Company of New Mexico [Member] | Mine Reclamation Trust [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Reclamation Trust Funding, Current fiscal year	4,000
Reclamation Trust Funding, Next fiscal year	5,000
Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency Accrual	25,400	25,700
Final Reclamation, capped amount to be collected	100,000
Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Underground [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency Accrual	9,100	8,600
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	56,500
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Underground [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	93,300
San Juan Generating Station [Member] | Coal Supply [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	$ 41,900	$ 37,300
Public Utilities, Estimated Increase in Coal Cost, Percentage	30.00%

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Significant Accounting Policies and Responsibility for Financial Statements - Narrative (Details) - USD ($)	1 Months Ended			3 Months Ended		6 Months Ended
	Jul. 31, 2015	Jun. 30, 2015	Jul. 31, 2014	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Common Stock, Dividends, Per Share, Declared			$ 0.185	$ 0.200	$ 0.185	$ 0.400	$ 0.37
Dividends, Common Stock, Cash						$ 15,931,000
Adjustments for New Accounting Pronouncement [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Unamortized Debt Issuance Expense		$ 11,800,000		$ 11,800,000		11,800,000
Public Service Company of New Mexico [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Dividends, Common Stock, Cash		20,000,000					$ 0
Public Service Company of New Mexico [Member] | Adjustments for New Accounting Pronouncement [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Unamortized Debt Issuance Expense		7,500,000		7,500,000		7,500,000
Texas-New Mexico Power Company [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Dividends, Common Stock, Cash		7,700,000					$ 6,800,000
Texas-New Mexico Power Company [Member] | Adjustments for New Accounting Pronouncement [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Unamortized Debt Issuance Expense		$ 4,200,000		$ 4,200,000		$ 4,200,000
Subsequent Event [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.200

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Regulatory and Rate Matters - Formula Transmission Rate Case (Details) - Formula Transmission Rate Case [Member] - Public Service Company of New Mexico [Member] $ in Millions			6 Months Ended
	May. 02, 2014 USD ($)	Jun. 03, 2013 USD ($)	Jun. 30, 2015 USD ($)	Mar. 20, 2015 party
Public Utilities, General Disclosures [Line Items]
Amount of Regulatory Costs Not yet Approved			$ 3.2
Public Utilities, Return on Equity			10.81%	10.00%
Percentage ownership of EIP transmission line			60.00%
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 0.5	$ 1.3
Number of other parties to settlement | party				5
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 1.3

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Related Party Transactions

6 Months Ended

Jun. 30, 2015

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,
	2015		2014		2015		2014
	(In thousands)
Services billings:
PNMR to PNM	$	21,340	$	22,190	$	44,067	$	43,256
PNMR to TNMP	6,591		6,963		13,680		14,224
PNM to TNMP	184		133		288		242
TNMP to PNMR	—		—		—		—
Interest billings:
PNMR to TNMP	54		83		133		180
PNMR to PNM	22		—		28		54
PNM to PNMR	26		25		55		51
Income tax sharing payments:
PNMR to PNM	—		—		1,450		—
PNMR to TNMP	—		—		—		—

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Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Earnings Per Share [Abstract]
Net Earnings Attributable to PNMR		$ 31,673	$ 29,141	$ 46,013	$ 41,609
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		99,000	110,000	105,000	146,000
Average Shares – Basic		79,753,000	79,764,000	79,759,000	79,800,000
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	[1]	380,000	464,000	384,000	508,000
Average Shares – Diluted		80,133,000	80,228,000	80,143,000	80,308,000
Net Earnings Per Share of Common Stock:
Basic (dollars per share)		$ 0.40	$ 0.37	$ 0.58	$ 0.52
Diluted (dollars per share)		$ 0.40	$ 0.36	$ 0.57	$ 0.52
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares)				245,950

[1] Excludes the effect of out-of-the-money options for 245,950 shares of common stock at June 30, 2015.

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Significant Accounting Policies and Responsibility for Financial Statements (Policies)

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

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

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

Dividends on Common Stock

Dividends on Common Stock

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

New Accounting Pronouncements

New Accounting Pronouncements

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

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

On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard was to be 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. On July 9, 2015, the FASB approved a one-year deferral in the effective date of ASU 2014-09, with early adoption as of the original effective date permitted. 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 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

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

Accounting Standards Update 2015-03 - Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs

On April 7, 2015, the FASB issued ASU No. 2015-03, which requires that issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction of the carrying amount of that debt and not as an asset. The ASU is effective for the Company for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is evaluating the impacts of the ASU. Currently, unamortized debt issuance costs that would be reclassified are included in other deferred charges on the Condensed Consolidated Balance Sheets and, at June 30, 2015, amounted to $11.8 million for PNMR, $7.5 million for PNM, and $4.2 million for TNMP.

Accounting Standards Update 2015-07 - Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)

On May 1, 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The new standard is effective for reporting periods beginning after December 31, 2016, with early adoption permitted. Once adopted, the update is required to be applied on a retrospective basis for all periods presented. The Company is in the process of analyzing this new standard; however, it is not expected to have a material impact on the financial statements other than the disclosure and presentation of certain investments of the Company’s employee benefit plans that are measured using the net asset value practical expedient.

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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Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - Transmission Cost of Service Rates [Member] - Texas-New Mexico Power Company [Member] - USD ($) $ in Millions		6 Months Ended
	Jul. 17, 2015	Sep. 15, 2015	Mar. 15, 2015	Sep. 07, 2014	Mar. 12, 2014
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base			$ 25.2	$ 18.2	$ 18.1
Annual Increase in Revenue			$ 4.2	$ 2.9	$ 2.8
Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base		$ 27.1
Annual Increase in Revenue	$ 1.4	$ 4.4
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 7.0

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Allowance for uncollectible accounts	$ 1,363	$ 1,466
Accumulated depreciation, nuclear fuel	$ 45,138	$ 44,507
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 outstanding	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	$ 1,363	$ 1,466
Accumulated depreciation, nuclear fuel	$ 45,138	$ 44,507
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	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net Earnings	$ 35,655	$ 33,181	$ 53,508	$ 49,312
Net earnings	31,673	29,141	46,013	41,609
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	(413)	3,999	3,744	6,046
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(5,087)	(3,397)	(7,624)	(5,369)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit)	905	780	1,810	1,560
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	0	0	0	(100)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	0	79	0	115
Net change after income taxes	(4,595)	1,461	(2,070)	2,252
Comprehensive Income	31,060	34,642	51,438	51,564
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,850)	(3,908)	(7,231)	(7,439)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Comprehensive Income Attributable to PNMR	27,078	30,602	43,943	43,861
Public Service Company of New Mexico [Member]
Net Earnings	25,363	24,254	38,866	35,460
Net earnings	21,513	20,346	31,635	28,021
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	(413)	3,999	3,744	6,046
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(5,087)	(3,397)	(7,624)	(5,369)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit)	905	780	1,810	1,560
Fair Value Adjustment for Cash Flow Hedges:
Net change after income taxes	(4,595)	1,382	(2,070)	2,237
Comprehensive Income	20,768	25,636	36,796	37,697
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,850)	(3,908)	(7,231)	(7,439)
Comprehensive Income Attributable to PNMR	16,918	21,728	29,565	30,258
Texas-New Mexico Power Company [Member]
Net Earnings	11,865	9,534	19,559	16,336
Net earnings	11,865	9,534	19,559	16,336
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	0	0	0	(100)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	0	79	0	115
Net change after income taxes	0	79	0	15
Comprehensive Income Attributable to PNMR	$ 11,865	$ 9,613	$ 19,559	$ 16,351

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Financing

6 Months Ended

Jun. 30, 2015

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 2014 Annual Reports on Form 10-K.

Financing Activities

On March 5, 2014, PNM entered into a $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 2013 Term Loan Agreement and other short-term amounts outstanding. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.14% at June 30, 2015, must be repaid on or before September 4, 2015, and is reflected in current maturities of long-term debt on the Condensed Consolidated Balance Sheets. The PNM 2014 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNM 2014 Term Loan Agreement has a cross default provision and a change of control provision.

On December 22, 2014, PNM entered into a multi-draw term loan facility (the “PNM Multi-draw Term Loan”) with JPMorgan Chase Bank, N.A., as Lender and Administrative Agent. The $125.0 million facility has a maturity date of June 21, 2016. At December 31, 2014, outstanding borrowings under the PNM Multi-draw Term Loan were $100.0 million. PNM drew the remaining capacity of $25.0 million on May 8, 2015 resulting in outstanding borrowings at June 30, 2015 of $125.0 million, which are included in current maturities of long-term debt on the Condensed Consolidated Balance Sheet. The PNM Multi-draw Term Loan bears interest at a variable rate, which was 0.77% at June 30, 2015. The PNM Multi-draw Term Loan includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Multi-draw Term Loan Agreement has a cross default provision and a change of control provision.

On March 9, 2015, PNMR entered into a $150.0 million Term Loan Agreement (“PNMR 2015 Term Loan Agreement”) between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and Administrative Agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate, which was 1.19% at June 30, 2015, and must be repaid on or before March 9, 2018. The PNMR 2015 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNMR 2015 Term Loan Agreement has a cross default provision and a change of control provision.

At December 31, 2014, PNMR had an aggregate outstanding principal amount of $118.8 million of its 9.25% Senior Unsecured Notes, Series A, which were due on May 15, 2015. PNMR repaid all of the 9.25% Senior Unsecured Notes, Series A at the scheduled maturity, utilizing proceeds from the PNMR 2015 Term Loan Agreement and borrowings under the PNMR Revolving Credit Facility.

At December 31, 2014, PNM had a $39.3 million series of outstanding Senior Unsecured Notes, Pollution Control Revenue Bonds, which have a final maturity of June 1, 2043. The PCRBs were subject to mandatory tender for remarketing on June 1, 2015 and were successfully remarketed on that date. The notes now bear interest at 2.40%, continue to have an outstanding amount of $39.3 million, and are subject to mandatory tender for remarketing on June 1, 2020.

Short-term Debt

The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. Both of these facilities mature on October 31, 2019 and provide for an additional one-year extension option, subject to approval by a majority of the lenders. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. The TNMP Revolving Credit Facility 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, 2015, TNMP had $4.1 million in borrowings from PNMR under its intercompany loan agreement. At June 30, 2015, the weighted average interest rate was 1.69% for the PNMR Revolving Credit Facility, 1.44% for the PNM Revolving Credit Facility, 1.44% for the PNM New Mexico Credit Facility, 1.19% for the TNMP Revolving Credit Facility, and 1.04% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2015. Short-term debt outstanding consisted of:

	June 30,		December 31,
Short-term Debt	2015		2014
	(In thousands)
PNM:
Revolving credit facility	$	31,100	$	—
PNM New Mexico Credit Facility	20,000		—
TNMP – Revolving credit facility	29,000		5,000
PNMR:
Revolving credit facility	7,500		600
PNMR Term Loan Agreement	100,000		100,000
	$	187,600	$	105,600

At July 24, 2015, PNMR, PNM, and TNMP had $293.2 million, $353.6 million, and $42.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $30.0 million of availability under the PNM New Mexico Credit Facility. Total availability at July 24, 2015, on a consolidated basis, was $719.7 million for PNMR. As of July 24, 2015, PNM had $18.7 million and TNMP had $13.2 million in borrowings from PNMR under their intercompany loan agreements. At July 24, 2015, PNMR, PNM and TNMP had consolidated invested cash of $1.9 million, none, and none.

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 24, 2015
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, 2015
Document Fiscal Year Focus	2015
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, 2015

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefit Plans

Pension and Other Postretirement Benefit Plans

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

Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2014 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.

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
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	51		$	45		$	—	$	—
Interest cost	7,064			7,541			1,023			1,159			190		205
Expected return on plan assets	(9,831		)	(9,511		)	(1,403		)	(1,410		)	—		—
Amortization of net (gain) loss	3,705			3,255			491			556			81		52
Amortization of prior service cost	(241		)	(241		)	(160		)	(336		)	—		—
Net periodic benefit cost	$	697		$	1,044		$	2		$	14		$	271	$	257
	Six Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	102		$	91		$	—	$	—
Interest cost	14,127			15,082			2,045			2,315			380		411
Expected return on plan assets	(19,662		)	(19,022		)	(2,805		)	(2,819		)	—		—
Amortization of net (gain) loss	7,410			6,510			983			1,113			162		105
Amortization of prior service cost	(483		)	(483		)	(321		)	(672		)	—		—
Net periodic benefit cost	$	1,392		$	2,087		$	4		$	28		$	542	$	516

PNM made contributions to its pension plan trust of zero and $30.0 million in the three and six months ended June 30, 2015 and made no contributions in the three and six months ended June 30, 2014. PNM does not anticipate making additional contributions to its pension trust in 2015.  Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the PNM pension plan trust for 2016-2019 are estimated to total $22.0 million. These anticipated contributions were developed using current funding assumptions, with discount rates of 4.8% 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, 2015 and $0.8 million and $1.6 million in the three and six months ended June 30, 2014. PNM expects to make contributions to the OPEB trust totaling $3.5 million in 2015 and $14.0 million for 2016-2019.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $0.9 million in the three and six months ended June 30, 2015 and $0.4 million and $0.7 million in the three and six months ended June 30, 2014 and are expected to total $1.5 million during 2015.

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
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	62		$	59		$	—	$	—
Interest cost	761			798			152			155			9		10
Expected return on plan assets	(1,105		)	(1,132		)	(130		)	(133		)	—		—
Amortization of net (gain) loss	195			166			—			(31		)	1		—
Amortization of prior service cost	—			—			—			8			—		—
Net Periodic Benefit Cost (Income)	$	(149	)	$	(168	)	$	84		$	58		$	10	$	10
	Six Months Ended June 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	124		$	119		$	—	$	—
Interest cost	1,521			1,597			304			309			18		20
Expected return on plan assets	(2,210		)	(2,263		)	(260		)	(267		)	—		—
Amortization of net (gain) loss	391			333			—			(61		)	2		—
Amortization of prior service cost	—			—			—			16			—		—
Net Periodic Benefit Cost (Income)	$	(298	)	$	(333	)	$	168		$	116		$	20	$	20

TNMP made no contribution to its pension trust in 2014 and does not anticipate making any contributions in 2015-2019 based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. These expectations were developed using current funding assumptions, including discount rates of 4.8% 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 no contributions to the OPEB trust in the three and six months ended June 30, 2015 and $0.3 million in the three and six months ended June 30, 2014. TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2015 and $1.4 million for 2016-2019. 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, 2015 and 2014 and are expected to total $0.1 million during 2015.

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Unrealized holding gains (losses) arising during the period, income tax benefit (expense)	$ 266	$ (2,602)	$ (2,413)	$ (3,809)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense (benefit)	3,278	2,210	4,913	3,488
Pension liability adjustment, income tax (expense) benefit	(583)	(508)	(1,166)	(1,016)
Change in fair market value, income tax benefit (expense)	0	0	0	53
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	0	(42)	0	(61)
Public Service Company of New Mexico [Member]
Unrealized holding gains (losses) arising during the period, income tax benefit (expense)	266	(2,602)	(2,413)	(3,809)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense (benefit)	3,278	2,210	4,913	3,488
Pension liability adjustment, income tax (expense) benefit	(583)	(508)	(1,166)	(1,016)
Texas-New Mexico Power Company [Member]
Change in fair market value, income tax benefit (expense)	0	0	0	53
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	$ 0	$ (42)	$ 0	$ (61)

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Accumulated Other Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2015

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, 2015 and 2014 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	PNM									TNMP		PNMR
	Unrealized									Fair Value
	Gain on			Pension						Adjustment
	Available-for-			Liability						for Cash Flow
	Sale Securities			Adjustment			Total			Hedges		Total
	(In thousands)
Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—	$	(61,755	)
Amounts reclassified from AOCI (pre-tax)	(12,537		)	2,976			(9,561		)	—		(9,561		)
Income tax impact of amounts reclassified	4,913			(1,166		)	3,747			—		3,747
Other OCI changes (pre-tax)	6,157			—			6,157			—		6,157
Income tax impact of other OCI changes	(2,413		)	—			(2,413		)	—		(2,413		)
Net change after income taxes	(3,880		)	1,810			(2,070		)	—		(2,070		)
Balance at June 30, 2015	$	24,128		$	(87,953	)	$	(63,825	)	$	—	$	(63,825	)

Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(57,877	)	$	(263	)	$	(58,140	)
Amounts reclassified from AOCI (pre-tax)	(8,857		)	2,576			(6,281		)	176			(6,105		)
Income tax impact of amounts reclassified	3,488			(1,016		)	2,472			(61		)	2,411
Other OCI changes (pre-tax)	9,855			—			9,855			(153		)	9,702
Income tax impact of other OCI changes	(3,809		)	—			(3,809		)	53			(3,756		)
Net change after income taxes	677			1,560			2,237			15			2,252
Balance at June 30, 2014	$	26,425		$	(82,065	)	$	(55,640	)	$	(248	)	$	(55,888	)

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, 2015 and 2014, approximately 23.0% and 23.0% of the amount reclassified was capitalized into construction work in process and approximately 2.7% and 2.1% was capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes” in the Condensed Consolidated Statements of Earnings.

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Segment Information

6 Months Ended

Jun. 30, 2015

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, 2015
Electric operating revenues	$	275,450		$	77,437		$	—		$	352,887
Cost of energy	95,728			18,310			—			114,038
Margin	179,722			59,127			—			238,849
Other operating expenses	103,541			20,807			(3,962		)	120,386
Depreciation and amortization	29,002			13,591			3,456			46,049
Operating income (loss)	47,179			24,729			506			72,414
Interest income	1,946			—			(5		)	1,941
Other income (deductions)	7,446			793			(673		)	7,566
Net interest charges	(19,681		)	(6,856		)	(2,376		)	(28,913		)
Segment earnings (loss) before income taxes	36,890			18,666			(2,548		)	53,008
Income taxes (benefit)	11,527			6,801			(975		)	17,353
Segment earnings (loss)	25,363			11,865			(1,573		)	35,655
Valencia non-controlling interest	(3,850		)	—			—			(3,850		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	21,381		$	11,865		$	(1,573	)	$	31,673
Six Months Ended June 30, 2015
Electric operating revenues	$	537,390		$	148,365		$	—		$	685,755
Cost of energy	193,594			36,089			—			229,683
Margin	343,796			112,276			—			456,072
Other operating expenses	207,557			42,567			(7,546		)	242,578
Depreciation and amortization	57,405			27,049			7,056			91,510
Operating income	78,834			42,660			490			121,984
Interest income	3,717			—			(26		)	3,691
Other income (deductions)	13,257			2,084			(2,452		)	12,889
Net interest charges	(39,640		)	(13,781		)	(5,765		)	(59,186		)
Segment earnings (loss) before income taxes	56,168			30,963			(7,753		)	79,378
Income taxes (benefit)	17,302			11,404			(2,836		)	25,870
Segment earnings (loss)	38,866			19,559			(4,917		)	53,508
Valencia non-controlling interest	(7,231		)	—			—			(7,231		)
Subsidiary preferred stock dividends	(264		)	—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	31,371		$	19,559		$	(4,917	)	$	46,013
At June 30, 2015:
Total Assets	$	4,544,279		$	1,268,862		$	113,877		$	5,927,018
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	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

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Goodwill

6 Months Ended

Jun. 30, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

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

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

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

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

An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units but a quantitative analysis for others. For the annual evaluations performed as of April 1, 2015 and 2014, 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, 2015 and 2014 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2015 and 2014 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 25% and 30%. 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, 2015 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 20 of Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2015

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 periodically 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 any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2014 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 alleged that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, and on October 7, 2014, APS received a settlement payment of $57.4 million for costs paid through June 30, 2011, for DOE’s failure to accept spent nuclear fuel generated at PVNGS. PNM’s share of the settlement was $5.9 million, substantially all of which was credited back to PNM’s customers. The settlement agreement also establishes a process for the payment of subsequent claims through December 31, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. On October 31, 2014, APS submitted a claim for costs paid between July 1, 2011 and June 30, 2014 and agreed to a settlement amount of $42.0 million in March 2015. PNM’s share of the settlement, which amounted to $4.3 million, including $3.1 million credited back to PNM’s customers, was recorded in the three months ended March 31, 2015. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At June 30, 2015 and December 31, 2014, PNM had a liability for interim storage costs of $12.5 million and $12.3 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 and temporary storage rule (the “Waste Confidence Decision”). The D.C. Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’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 Waste Confidence Decision update for further action consistent with NEPA. On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision. The NRC commissioners also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.

In September 2013, the NRC issued its draft generic EIS to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel.  The continued storage rule adopted the findings of the generic EIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although PVNGS had not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. PNM is unable to predict the outcome of this matter.

PVNGS has sufficient capacity at its on-site ISFSI to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027.  Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047.  If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of DOE’s intention to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of its 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 required installation of selective catalytic reduction technology (“SCR”) on all four units by September 21, 2016. In November 2012, EPA approved all components of the SIP, except for the NOx BART determination for SJGS, which continued to be subject to the FIP.

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

During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised 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.

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013 and NMED developed a RSIP, both of which reflect the terms of the non-binding agreement. The EIB approved the RSIP in September 2013 and it was submitted to EPA for approval in October 2013. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and became effective on November 10, 2014.

Conversion of SJGS Units 1 and 4 to balanced draft technology (“BDT”) is included with the installation of SNCRs in the RSIP. The requirement to install BDT was made binding and enforceable in the NSR permit that accompanied the RSIP submitted to the EPA. EPA’s rule approving the RSIP specifically references the NSR permit by including a condition that requires “modification of the fan systems on Units 1 and 4 to achieve ‘balanced’ draft configuration ….”

Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM took steps to commence installation of SCRs at SJGS. In October 2012, PNM entered into a contract with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million. The costs for the project to install SCRs would encompass installation of BDT equipment to comply with the NAAQS requirements described below. The construction contract was terminated in December 2014 following approval of the RSIP by EPA.

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 BDT equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS.

The above estimates include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM’s share of the costs described above would have been about 46.3%.

Following the February 2013 development of the alternative BART compliance plan, PNM began taking steps to prepare for the potential installation of SNCR and BDT equipment on Units 1 and 4 due to the long lead times on certain equipment purchases. In May 2013, PNM entered into an equipment and related services contract with a technology provider. In July 2014, PNM entered into a contract for management of the construction and in September 2014 entered into a construction and procurement contract. Installation of SNCRs and BDT on SJGS Unit 1 was completed in April 2015 and PNM anticipates that installation of SNCRs and BDT on Unit 4 can be completed within the timeframe contained in the RSIP.

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

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

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

• An order allowing cost recovery for PNM’s share of the installation of SNCR and BDT 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 have been a reduction of 340 MW in PNM’s ownership of SJGS

The December 20, 2013 NMPRC filing identified a new 177 MW natural gas-fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 12. On June 30, 2015, PNM filed an application for a CCN for the gas facility, which is currently contemplated to be rated at 187 MW, to be located at SJGS. PNM estimates the cost of these identified resources would be approximately $212.5 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs would be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of SNCR and BDT equipment.

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 regarding ownership restructuring and other matters (see SJGS Ownership Restructuring Matters below). In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements were memorialized in the resolution and term sheet described below.

On October 1, 2014, PNM, the staff of the NMPRC, the NMAG, New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico filed a stipulation with the NMPRC. NMIEC subsequently joined the agreement. New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico have since withdrawn support of the stipulation. Statements of opposition were filed by other intervenors.

Under the terms of the stipulation, PNM:

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

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

• Would recover 50% of the estimated $231 million undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a twenty year period and would include a return on the unrecovered amount at PNM’s WACC; at June 30, 2015, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $278 million

• Would be granted a CCN for 134 MW of PVNGS Unit 3 at a January 1, 2018 value of $221.1 million ($1,650 per KW); PNM’s ownership share of PVNGS would also be subject to a capacity factor performance threshold of 75% for a seven year period beginning January 1, 2018; subject to certain exceptions, if the capacity factor is not achieved in any year, PNM would refund the cost of replacement power through its FPPAC; at June 30, 2015, PNM’s net book value of PVNGS Unit 3 was approximately $147 million

• Would file for recovery of its reasonable and prudent costs of installation of the SNCR and BDT equipment requirements at SJGS Units 1 and 4 up to $90.6 million

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

A public hearing in the NMPRC case was held in January 2015. In connection with the hearing, PNM filed testimony indicating that:

• PNM would not acquire the 65 MW of capacity in SJGS Unit 4 that was no longer anticipated to be acquired by the City of Farmington, as discussed under SJGS Ownership Restructuring Matters below

• PNM would not enter into a coal supply agreement for SJGS that extends beyond 2022 without NMPRC approval

• PNM would have an ownership restructuring agreement for SJGS in place by May 1, 2015

If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. Although PNM would record the regulatory disallowance upon approval by the NMPRC and satisfaction of any material conditions precedent, the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order, as well as PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3 and PVNGS Unit 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values of the plants. Based on the provisions of the stipulation as filed and PNM’s current projection of December 31, 2017 book values, PNM estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.

On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommends that the NMPRC reject the stipulation as proposed. The certification recommends that the abandonment of SJGS Units 2 and 3 be conditionally approved subject to PNM proposing adequate replacement capacity, approval of the CCN for PVNGS Unit 3 at its net book value on December 31, 2017, approval of recovery of an estimated $128.5 million, representing 50% of the remaining undepreciated investment in SJGS Units 2 and 3 at December 31, 2017, and denial of the CCN for the additional 132 MW of Unit 4 of SJGS. The certification states that PNM may re-apply for a CCN for the 132 MW after it has presented final restructuring and post-2017 coal supply agreements for SJGS. On April 20, 2015, PNM filed exceptions to the certification. PNM argued that the proposed modifications to the stipulation do not balance customer and shareholder interests, upset the balance contained in the stipulation, that the schedule recommended by the Hearing Examiner for PNM to file a replacement plan would effectively preclude the inclusion of the 132 MW of additional SJGS Unit 4 capacity in the replacement plan thereby jeopardizing the restructuring agreement and the continued operation of SJGS to the detriment of customers, and that the Hearing Examiner erred in recommending a lower rate base value for PNM’s share of PVNGS Unit 3. If the NMPRC issues an order that modifies the stipulation, any stipulating party can void the stipulation. The certification recommends that the parties be given seven days to decide whether to accept any modifications after the NMPRC issues an order. The NMPRC can approve, reject, or modify the certification. If the NMPRC were to issue an order adopting all of the modifications to the stipulation recommended by the Hearing Examiner, PNM estimates the net pre-tax regulatory disallowance referenced above would become an amount between $145 million and $155 million.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of confidential, substantially final, unexecuted restructuring, coal supply, and related agreements for SJGS. See SJGS Ownership Restructuring Matters and Coal Supply below. On May 27, 2015, the NMPRC issued an order requiring PNM to file executed restructuring and coal supply agreements by July 1, 2015. The order provided that PNM could request an extension of the required filing date to August 1, 2015 if such request was based on specific and verifiable facts. PNM subsequently requested an extension, citing that certain of the owners of SJGS were governmental entities and required the additional time in order to meet statutory public notice and meeting requirements. The NMPRC granted PNM an extension to August 1, 2015 to file the executed restructuring agreement. On July 1, 2015, PNM filed the executed coal supply and related agreements described under Coal Supply below with the NMPRC. On July 1, 2015, PNM also filed partially executed agreements related to restructuring discussed under SJGS Ownership Restructuring Matters below. On July 31, 2015, PNM filed fully executed restructuring agreements, along with testimony supporting the agreements and a CCN for the 132 MW of additional SJGS Unit 4 capacity.

In June 2015, a NMPRC Commissioner issued an order designating a facilitator to determine whether an uncontested settlement among some or all of the parties in this case could be accomplished. A mediation process is on-going. A public hearing on PNM’s application concerning BART for SJGS is scheduled to begin on September 30, 2015. Although PNM expects a decision from the NMPRC in the fourth quarter of 2015, PNM is unable to predict what action the NMPRC will take, whether any party will void the stipulation, or the ultimate outcome of this matter.

SJGS Ownership Restructuring Matters – As discussed in the 2014 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 currently effective contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. The California participants have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4.

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

On June 26, 2014, a non-binding resolution (the “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 Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCR and BDT equipment, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating 58.7%. On September 2, 2014, the SJGS Coordination Committee adopted a non-binding supplement to the Resolution, which provides for allocation of future costs of decommissioning among current SJGS owners using a time-based sliding scale and outlines indemnification obligations. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants would need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, on July 1, 2015, PNM entered into an agreement for the supply of coal to SJGS through June 30, 2022.

In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the Resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. PNM filed the Fuel and Capital Funding Agreement with FERC on September 18, 2014, with a request for a retroactive effective date to July 1, 2014. FERC approved the request on November 13, 2014.

On January 7, 2015, the City of Farmington, New Mexico, which has an ownership interest in Unit 4, notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs in that unit unsubscribed. As discussed under NMPRC Filing above, PNM has indicated that it will not acquire any of the unsubscribed MWs. However, PNMR currently anticipates that PNMR Development would acquire the 65 MWs. The City of Farmington’s action was taken under the Fuel and Capital Funding Agreement and has the impact of negating certain provisions of that agreement, including the payment arrangement related to SNCRs and PNM’s acquisition of the exiting participants’ coal inventory described above, and reinstating the voting and capital improvement cost allocations under the current SJPPA. Accordingly, on February 3, 2015, PNM informed the participants in the Fuel and Capital Funding Agreement that the agreement would terminate by its terms no later than February 6, 2015. The City of Farmington and the other continuing participants in SJGS have indicated that they remain committed to on-going ownership in SJGS.

On May 19, 2015, PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 entered into a Capacity Option and Funding Agreement (“COFA”), which provides PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. PNMR’s current projection of capital expenditures includes those of PNMR Development for the 65 MW. PNMR guarantees the obligations of PNMR Development under the COFA. The COFA will terminate on the earliest of January 1, 2016, the effective date of a SJGS restructuring agreement, the date PNM notifies the other parties that it has failed to receive required regulatory approvals for the SJGS restructuring, the date any California owner opposes PNM’s application before the NMPRC, or the date PNM elects to terminate because another SJGS owner has given notice that it will no longer participate in the restructuring process. If the COFA is terminated, the California owners would not be obligated to repay amounts funded by PNM and PNMR Development. On June 23, 2015, ABCWUA filed a motion with the NMPRC to void the COFA alleging that the COFA violated the NMPRC’s rules regarding affiliate transactions.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of a confidential, substantially final, unexecuted copy of the San Juan Project Restructuring Agreement (“RA”). The RA sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the Resolution. PNMR Development would also be a party to the RA and would acquire an ownership interest in SJGS Unit 4 when the California owners exit, but would have obligations related to Unit 4 before then. On December 31, 2017, PNM would acquire 132 MW of the capacity in SJGS Unit 4 from the California owners and PNMR Development would acquire 65 MW of such capacity, as contemplated by the COFA. The RA is dependent on and would become effective upon the last of the approval by NMPRC, the approval by FERC, the approval of each participant’s board or other decision-making body, and the effective date of a new coal supply agreement for SJGS. It is currently anticipated that the new coal supply agreement and the RA would become effective contemporaneously on January 1, 2016. The RA sets forth the terms under which PNM would acquire the coal inventory of the exiting SJGS participants on January 1, 2016 and provide coal supply to the exiting participants during the period from January 1, 2016 through December 31, 2017, which arrangement PNM believes will provide economic benefits that will be passed on to PNM’s customers. The RA also includes provisions whereby the exiting owners will make payments to certain of the remaining participants, not including PNM, related to the restructuring. PNM’s notice also included submittal of confidential, substantially final, unexecuted copies of documents related to coal supply for SJGS beginning January 1, 2016 (see “Coal Supply” below). On July 1, 2015, PNM filed with the NMPRC fully executed coal supply and related agreements along with a partially executed RA, an agreement covering decommissioning obligations and funding for the SJGS plant, and related amendments to the SJPPA. PNM filed fully executed RA and related agreements along with supporting testimony on July 31, 2015.

PNM is unable to predict whether all required approvals will be obtained and other conditions satisfied in order for the agreements discussed above to become effective and restructuring to be consummated.

Other SJGS Matters – 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 BDT requirements described above, to the SJGS participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. In addition, other capital projects related to Unit 4 were not approved by the participants. PNM subsequently requested that the owners of Unit 4 approve the expenditure of costs critical to being able to comply with the time frame in the RSIP with respect to the Unit 4 project of $1.9 million on March 10, 2014, $6.4 million on June 27, 2014, and total project expenses of $76.6 million (including the two prior requests) on January 22, 2015. The Unit 4 owners did not approve these requests.

PNM, in its capacity as operating agent of SJGS, is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM must evaluate its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and take reasonable and prudent actions as it deems necessary. Therefore, on March 10, 2014, July 14, 2014, and March 20, 2015, PNM, as operating agent for SJGS, issued “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.

As discussed above, EPA approved the RSIP and withdrew the FIP on October 9, 2014 and those approvals became effective on November 10, 2014. PNM believes significant progress is being made towards implementation of the RSIP. However, the final implementation of the RSIP is still dependent upon PNM obtaining NMPRC approval to retire San Juan Units 2 and 3 and the agreements for restructuring and a new coal supply becoming effective. PNM can provide no assurance that these requirements will be accomplished. If the RSIP requirements ultimately are not implemented due to adverse or alternative regulatory, legislative, legal, or restructuring developments or other factors, PNM would need to pursue other alternatives to address compliance with the CAA.Failure to implement the RSIP or an agreed to alternative could jeopardize the economic viability of SJGS. PNM will seek recovery from its ratepayers for costs that may be incurred as a result of the CAA requirements. PNM is unable to predict the ultimate outcome of these matters.

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

Four Corners

On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to permanently close 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 shut down 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.

On December 30, 2013, APS announced the closing of its purchase of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. Concurrently with the closing of the SCE transaction, the ownership of the coal supplier and operator of the mine that serves Four Corners was transferred to a company formed by the Navajo Nation to own the mine and develop other energy projects. Also occurring concurrently, the Four Corners co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031.

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 was undertaken 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 EIS was finalized on May 1, 2015. On July 17, 2015, DOI issued a Record of Decision, which approves the 25-year site lease extension with the Navajo Nation for Four Corners, authorizes continued mining operations to supply the remaining units at Four Corners, renews transmission line and access road rights-of-way on the Navajo and Hopi Reservations, and accepts the proposed mining plan for the Navajo Mine. The record of decision provides the authority for the Bureau of Indian Affairs to sign the lease amendments and rights-of-way renewals, which are anticipated to occur in the near future.  In addition, installation of SCR control technology at Four Corners requires a PSD permit, which APS received in December 2014.

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 $91.8 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.

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.  On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposes deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO₂ emissions. The settlement results from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree requires the following: 1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO₂ in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; 2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule.  SJGS and Four Corners SO₂ emissions are below the tonnages set forth in 1) above. EPA regions sent out letters to state environmental agencies explaining how EPA plans to implement the consent decree.  The letters outline the schedule that EPA expects states to follow in moving forward with new SO₂ non-attainment designations. NMED did not receive a letter.

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 NSR air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. The revised permit requires the reduction of SO₂ emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and continues to require the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO₂, and particulate matter. These reductions will help SJGS meet the NAAQS. The BDT equipment modifications are to 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. 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 60-70 parts per billion (“ppb”). On December 17, 2014, EPA published a proposed rule that would revise the NAAQS for ground level ozone. The rule would reduce the current primary 8-hour ozone NAAQS from 75 ppb to between 70 and 65 ppb. EPA is proposing a secondary standard to provide protection against cumulative exposures that can damage plants and trees. To achieve this level of protection, EPA is proposing to set an 8-hour secondary standard at a level within the range of 65 to 70 ppb. According to EPA, 2011-2013 ozone ambient air monitoring data indicates that Bernalillo, Dona Ana, Eddy, and San Juan counties in New Mexico exceed a 70 ppb ozone concentration. In addition, Lea, Luna, Santa Fe, and Valencia counties exceed the 65 ppb ozone concentration. Counties that exceed the ozone NAAQS would be designated as nonattainment for ozone. NMED would have responsibility for bringing those counties 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 controls to meet a new ozone NAAQS. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional controls would be required at any of its affected facilities as a result of ozone non-attainment designation. EPA is under a court order to finalize the ozone standard by October 1, 2015.

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 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties’ dispute is deemed settled.

In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM’s mercury controls. NMED and plaintiffs sought to require PNM to implement additional mercury controls. PNM estimated the implementation would increase annual mercury control costs for the entire station, which are currently $0.7 million, to a total of $6.6 million. On March 23, 2014, the court entered a stipulated order reflecting an agreement reached by the parties. Under the stipulated order, PNM was required to repeat the mercury study required under the Consent Decree using sorbent traps instead of the continuous emissions monitoring system used in the initial study. The results of the mercury study would establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM completed stack testing and submitted the study report to NMED and the plaintiffs in December 2014. Based on PNM’s cost/benefit analysis, PNM recommended that the carbon injection not be increased from its current level. On March 18, 2015, NMED and the plaintiffs approved PNM’s recommendation for the activated carbon injection rate. The NSR permit issued by NMED on May 14, 2015 incorporates this operational parameter as a permit condition.

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 parties have agreed on terms of a settlement. The terms of the settlement do not have a material impact on PNM.  On June 24, 2015, the United States Department of Justice (“DOJ”) lodged the executed consent decree with the United States District Court for the District of New Mexico. On that same day, DOJ also published notice of the filing in the Federal Register, which opened a 30-day period for public comment. The settlement would resolve claims by the government and environmental plaintiffs that the co-owners violated the CAA by modifying Four Corners Units 4 and 5 without first obtaining a pre-construction permit from EPA. The settlement would require installation of pollution control technology and implementation of other measures to reduce SO₂ and NOx emissions from the two units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule BART requirements. The settlement would also require Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.2 million for certain environmental mitigation projects to benefit the Navajo Nation. PNM would be responsible for 13% of these costs based on its ownership interest in the units at the time of the alleged violations, which PNM recorded in 2014. At the end of the 30-day comment period, the United States will file a motion with the Court to advise the court of any comments received and of the United States’ position as to whether the proposed decree should be approved and entered by the court.

Four Corners Coal Mine

In 2012, several environmental groups filed a lawsuit in federal district court against the OSM challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners (“Area IV North”). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes action to cure the defect in its permitting process identified by the court. APS has indicated that the owner of the mine does not anticipate any near-term interruption of coal supply to the plant as a result of the suspension of mining in Area IV North. PNM cannot predict the time period that will be required for OSM’s further permitting process to be completed or whether the outcome of the process will be sufficient to allow the permit to be reinstated.

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 NEPA violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents.  WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. Legal briefing is complete. The matter has been stayed until August 21, 2015 by the court so that the parties can engage in settlement negotiations. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and SJGS. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation’s authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the 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 signed its final cooling water intake structures rule on May 16, 2014, which establishes national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The final rule was published on August 15, 2014 and became effective October 14, 2014.

The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting Best Technology Available (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and 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. The renewal date for the SJGS National Pollutant Discharge Elimination System (“NPDES”) permit is March 31, 2016; however, additional time to submit the application may be allowed by the NPDES permit writer. Because of the discretion afforded to EPA with respect to entrainment requirements, PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. However, the costs are not expected to be material. APS is currently in discussions with EPA Region 9, the NPDES 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. 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 PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM’s obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced similar results. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property.  This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels, and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. It is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels.  Additional testing and analysis will need to be performed before conclusions can be reached regarding the cause of the increased nitrate levels or the method and cost of remediation.  PNM is unable to predict the outcome of these matters.

Coal Combustion Byproducts Waste Disposal

CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners.  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 included two options for waste designation of coal ash. One option was 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 was 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 is developing a proposed rule governing the placement of CCBs at coal mining and reclamation operations. 

On January 29, 2014, in a consolidated case in the D.C. Circuit involving several environmental groups, including Sierra Club, and industry group members, the court issued 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.

On December 19, 2014, EPA issued its coal ash rule, including a non-hazardous waste determination for coal ash. Coal ash will be regulated as a solid waste under Subtitle D of RCRA. The rule does not cover mine placement of coal ash and OSM is expected to publish a rule covering mine placement in 2015. It is expected that OSM will be influenced by EPA’s rule. Because the rule is promulgated under Subtitle D, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non-compliance with the new requirements. EPA published the final CCB rule in the Federal Register on April 17, 2015. PNM is continuing to review the rule to fully understand its implications, but does not expect it to have a material impact on PNM’s operations, financial position, or cash flows.

The rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCB rules. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s 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 were required to comply with the MATS rule by April 16, 2015, unless the facility was granted a 1-year extension under CAA section 112(i)(3). PNM has control technology on each of the four units at SJGS that provides 99% mercury removal efficiency. The plant is in compliance with the MATS and no changes at SJGS are anticipated as a result of the Supreme Court action. Therefore, PNM did not request an extension and began complying with the MATS rule by the date specified in the rule. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule. 

On June 29, 2015, the United States Supreme Court issued its decision overturning the MATS rule. The justices ruled that EPA should have taken costs to utilities and others in the power sector into consideration before issuing the MATS rule. The case is now remanded to the D.C. Circuit for further proceedings consistent with the opinion.

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are currently 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, 2015 and December 31, 2014, prepayments for coal, which are included in other current assets, amounted to $41.9 million and $37.3 million. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement (“UG-CSA”) to supply processed coal for operation of SJGS through 2017. The parties to the UG-CSA are SJCC, PNM, and Tucson. Under the UG-CSA, 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 UG-CSA. The UG-CSA contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS after the expiration of the current coal sales agreement. As discussed under SJGS Ownership Restructuring Matters above, the Resolution and the non-binding term sheet approved by the SJGS Coordination Committee on June 26, 2014 recognize that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants would need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017. The remaining participants began the process of negotiating agreements concerning future fuel supply for SJGS. On October 1, 2014, the San Juan Fuels Committee approved a resolution authorizing an amendment to the UG-CSA. The amendment provided for the negotiation of a potential purchase transaction for the mine assets by one or more of the utilities, an affiliate, or another entity agreed to by the parties to be consummated on or before December 31, 2016. The amendment, which was effective as of October 2, 2014, also released the parties from the obligation to negotiate an extension of the UG-CSA, but does not impact the utilities’ option to purchase the mining assets at the end of the current contract term if the purchase transaction is not completed.

Following extensive negotiations among the SJGS participants, the owner of SJCC, and third-party miners, substantially final, unexecuted forms of agreements were negotiated under which the ownership of SJCC would transfer to a new third-party miner and PNM would enter into a new Coal Supply Agreement (“CSA”) and agreements for CCB disposal and mine reclamation services with SJCC on or about January 1, 2016. On May 1, 2015, PNM filed a notice of submittal of confidential, substantially final, unexecuted copies of the CSA, the mine reclamation agreement, and the CCB disposal agreement with the NMPRC. Effectiveness of the agreements would be dependent upon the closing of the purchase of SJCC by the new third-party miner and the finalization of the RA and other agreements, which along with regulatory approvals are necessary for the restructuring of ownership in SJGS to be consummated. On May 14, 2015, PNM and Westmoreland Coal Company (“Westmoreland”) entered into a letter agreement whereby each party agreed to enter into and deliver the CSA, the mine reclamation agreement, and the CCB disposal agreement on terms substantially in the form submitted to the NMPRC on May 1, 2015.

The NMPRC issued an order on May 27, 2015 requiring that PNM file executed agreements related to coal supply by July 1, 2015. On July 1, 2015, PNM and Westmoreland entered into the CSA, pursuant to which Westmoreland would supply all of the coal requirements of SJGS through June 30, 2022, under substantially the same terms as were contemplated by the unexecuted CSA with SJCC filed with the NMPRC on May 1, 2015. PNM and Westmoreland also entered into agreements under which Westmoreland will provide CCB disposal and mine reclamation services. Contemporaneous with the entry into the coal-related agreements, Westmoreland entered into a stock purchase agreement on July 1, 2015 that provides that Westmoreland will acquire all of the capital stock of SJCC. Upon closing under the stock purchase agreement, Westmoreland’s rights and obligations under the CSA and the agreements for CCB disposal and mine reclamation services will be assigned to SJCC. PNM and Westmoreland also entered into an agreement to terminate the May 14, 2015 letter agreement. In addition, PNM, TEP, SJCC, and SJCC’s owner entered into an agreement to terminate the existing UG-CSA upon the effective date of the new CSA. The CSA and related agreements will become effective upon the closing of that stock purchase agreement and the effectiveness of the RA. If the CSA does not become effective, the UG-CSA would remain in effect through its contractual expiration on December 31, 2017. The CSA and related agreements were filed with the NMPRC on July 1, 2015.

Pricing under the CSA would primarily be fixed, adjusted to reflect general inflation. The pricing structure takes into account that SJCC has been paid for coal mined but not delivered, as discussed above. PNM would have the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. The RA sets forth terms under which PNM will supply coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and to the SJGS remaining participants over the term of the CSA. PNM anticipates that coal costs under the CSA will be significantly less than under the current arrangement with SJCC. Since substantially all coal costs are passed through PNM’s FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners, which is discussed above, would be passed through to PNM’s customers.

It is currently anticipated that the CSA and the RA would become effective contemporaneously on January 1, 2016. PNM cannot predict if all of the necessary requirements will be satisfied and all approvals obtained in order for these agreements to become effective.

Four Corners

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, beginning in July 2016 and 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 30% at the inception of the new contract. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

Coal Mine Reclamation

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 current 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 2014 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $56.5 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, 2015. At June 30, 2015 and December 31, 2014, liabilities, in current dollars, of $25.4 million and $25.7 million for surface mine reclamation and $9.1 million and $8.6 million for underground mine reclamation were recorded in other deferred credits. On June 1, 2012, the SJGS owners entered into a trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the UG-CSA. As part of the restructuring of SJGS ownership (See SJGS Ownership Restructuring Matters above), SJGS owners and PNMR Development have negotiated the terms of an amended agreement to provide funding to compensate SJCC for post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable trust, and periodically deposit funding into the trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. PNM funded $1.0 million in 2014, $0.3 million in 2013, and $3.5 million in 2012. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels for 2015 and 2016. PNM anticipates funding approximately $4.0 million in 2015 and $5.0 million in 2016 based on the interim funding requirements.

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, which was performed in 2013, 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. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. Regulatory determinations made by the NMPRC may also affect the impact on PNM. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

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 although the BLM has indicated that final action on the proposed rule is scheduled for October 2015.

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.

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 9.4%, 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. NMTRD denied the refund claim. 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. On June 30, 2015, the court ruled that the assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. NMTRD has indicated it intends to appeal the decision. PNM cannot predict the timing or outcome of this litigation. However, PNM does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.

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 $13.4 billion per occurrence. Commercial insurance carriers provide $375 million and $13.0 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 $5.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions.

Water Supply

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

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

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

PVNGS Water Supply Litigation

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

San Juan River Adjudication

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

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

Rights-of-Way Matter

On January 28, 2014, the County Commission of Bernalillo County, New Mexico passed an ordinance requiring utilities to enter into a use agreement and pay a yet to be determined fee as a condition to installing, maintaining, and operating facilities on county rights-of-way. The fee is purported to compensate the county for costs of administering, maintaining, and capital improvements to the rights-of-way. On February 27, 2014, PNM and other utilities filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. The court denied the utilities’ motion for judgment. The court further granted the County’s motion to dismiss the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. In subsequent briefing in federal court, the County filed a motion for judgment on one of the utilities’ claims, which was granted by the court, leaving a claim regarding telecommunications service as the remaining federal claim. This matter is ongoing in state court. The utilities and Bernalillo County reached a standstill 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 challenges to the ordinance are unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS’ fuel cost adjustment clause practices and issues relating to demand cost allocation (the “Golden Spread Proceeding”). In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM (“SPS 2006 Rate Proceeding”). In 2008, FERC issued its order in the Golden Spread Proceeding affirming an ALJ decision that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues that had been ordered by the ALJ.  FERC also reversed the decision of the ALJ, which had been favorable to PNM, on the demand cost allocation issues. PNM and SPS filed petitions for rehearing and clarification of the scope of the remedies that were ordered and seeking reversal of various rulings in the order. On August 15, 2013, FERC issued separate orders in the Golden Spread Proceeding and in the SPS 2006 Rate Proceeding. The order in the Golden Spread Proceeding determined that PNM was not entitled to refunds for SPS’ fuel cost adjustment clause practices. That order and the order in the SPS 2006 Rate Proceeding decided the demand cost allocation issues using the method that PNM had advocated.  PNM, SPS, and other customers of SPS have filed requests for rehearing of these orders and they are pending further action by FERC. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes.

Navajo Nation Allottee Matters

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

In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice.  On April 2, 2014, the allotees’ appeal was dismissed with prejudice. 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.  On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested.  The letter indicated that the renewals were not approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. On July 13, 2015, PNM filed a condemnation action in the United States District Court for the District of New Mexico regarding the approximately 15.49 acres of land at issue. PNM cannot predict the outcome of this litigation.

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Fair Value of Derivative and Other Financial Instruments

6 Months Ended

Jun. 30, 2015

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 2014 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. During the six months ended June 30, 2015 and the year ended December 31, 2014, 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, 2015			December 31, 2014
PNMR and PNM	(In thousands)
Current assets	$	4,550		$	11,232
	4,550			11,232
Current liabilities	(1,153		)	(1,209		)
Long-term liabilities	—			(477		)
	(1,153		)	(1,686		)
Net	$	3,397		$	9,546

Included in the above table are $1.5 million of current assets at June 30, 2015 and $3.0 million of current assets at December 31, 2014 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, 2015 and December 31, 2014.

At June 30, 2015 and December 31, 2014, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at June 30, 2015 and December 31, 2014, amounts posted as cash collateral under margin arrangements were $1.6 million and $3.8 million for both PNMR and PNM. At June 30, 2015 and December 31, 2014, obligations to return cash collateral were $0.2 million and $0.2 million, for both PNMR and PNM. 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 less than $0.1 million of current assets at June 30, 2015 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. At December 31, 2014, there were no hedges in place under this plan.

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,
	2015			2014			2015			2014
PNMR and PNM	(In thousands)
Electric operating revenues	$	1,003		$	(324	)	$	531		$	(4,475	)
Cost of energy	(99		)	57			(149		)	245
Total gain (loss)	$	904		$	(267	)	$	382		$	(4,230	)

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
PNMR and PNM
June 30, 2015	865,000	(968,305	)
December 31, 2014	650,000	(1,919,000	)

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)
PNMR and PNM
June 30, 2015	$	1,143	$	—	$	83
December 31, 2014	$	1,686	$	—	$	167

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently 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, 2015, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium.  Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales.

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 serving SJGS (Note 11). At June 30, 2015 and December 31, 2014, the fair value of available-for-sale securities included $247.8 million and $244.6 million for the NDT and $5.7 million and $5.5 million for the mine reclamation trust. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.

	June 30, 2015				December 31, 2014
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,940	$	—	$	8,276
Equity securities:
Domestic value	15,015		45,750		17,418		45,340
Domestic growth	19,850		78,515		21,354		74,053
International and other	1,147		17,057		156		16,599
Fixed income securities:
U.S. Government	276		30,421		903		22,563
Municipals	3,098		58,986		5,851		68,973
Corporate and other	411		18,881		666		14,341
	$	39,797	$	253,550	$	46,348	$	250,145

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. Gross realized losses shown below exclude the change in realized impairment losses of $(1.2) million and $(0.8) million for the three and six months ended June 30, 2015 and $0.1 million and $0.6 million for the three and six months ended June 30, 2014.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands)
Proceeds from sales	$	62,670		$	30,316		$	94,522		$	53,119
Gross realized gains	$	8,329		$	5,364		$	13,465		$	8,482
Gross realized (losses)	$	(1,578	)	$	(755	)	$	(3,119	)	$	(1,794	)

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 securities impairments considered to be “other than temporary” included in AOCI. All such impairments have been recognized in earnings.

At June 30, 2015, 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	$	4,656	$	17,230	$	17,230
After 1 year through 5 years	21,533		639		—
After 5 years through 10 years	22,577		—		—
After 10 years through 15 years	10,137		—		—
After 15 years through 20 years	10,727		—		—
After 20 years	38,658		—		—
	$	108,288	$	17,869	$	17,230

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. 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 three and six months ended June 30, 2015 and the year ended December 31, 2014.

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, 2015 and December 31, 2014 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, 2015	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,940		$	3,940	$	—
Equity securities:
Domestic value	45,750			45,750		—
Domestic growth	78,515			78,515		—
International and other	17,057			17,057		—
Fixed income securities:
U.S. Government	30,421			29,131		1,290
Municipals	58,986			—		58,986
Corporate and other	18,881			4,119		14,762
	$	253,550		$	178,512	$	75,038
Commodity derivative assets	$	4,550		$	—	$	4,550
Commodity derivative liabilities	(1,153		)	—		(1,153		)
Net	$	3,397		$	—	$	3,397
December 31, 2014
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	8,276		$	8,276	$	—
Equity securities:
Domestic value	45,340			45,340		—
Domestic growth	74,053			74,053		—
International and other	16,599			16,599		—
Fixed income securities:
U.S. Government	22,563			20,808		1,755
Municipals	68,973			—		68,973
Corporate and other	14,341			4,843		9,498
	$	250,145		$	169,919	$	80,226
Commodity derivative assets	$	11,232		$	—	$	11,232
Commodity derivative liabilities	(1,686		)	—		(1,686		)
Net	$	9,546		$	—	$	9,546

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, 2015	(In thousands)
PNMR
Long-term debt	$	2,031,158	$	2,205,847	$	—	$	2,205,847	$	—
Investment in PVNGS lessor notes	$	16,568	$	17,230	$	—	$	—	$	17,230
Other investments	$	507	$	1,146	$	507	$	—	$	639
PNM
Long-term debt	$	1,515,676	$	1,644,887	$	—	$	1,644,887	$	—
Investment in PVNGS lessor notes	$	16,568	$	17,230	$	—	$	—	$	17,230
Other investments	$	265	$	265	$	265	$	—	$	—
TNMP
Long-term debt	$	365,482	$	410,961	$	—	$	410,961	$	—
Other investments	$	242	$	242	$	242	$	—	$	—
December 31, 2014
PNMR
Long-term debt	$	1,975,090	$	2,173,117	$	—	$	2,173,117	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	1,762	$	2,375	$	639	$	—	$	1,736
PNM
Long-term debt	$	1,490,657	$	1,624,222	$	—	$	1,624,222	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	397	$	397	$	397	$	—	$	—
TNMP
Long-term debt	$	365,667	$	427,356	$	—	$	427,356	$	—
Other investments	$	242	$	242	$	242	$	—	$	—

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Commitments and Contingencies - Royalty Rates, Tax Assessment, Insurance and Other Matters (Details) $ in Millions	Jul. 13, 2015 a	Jun. 30, 2015 USD ($)	Jan. 22, 2015 Allotment_Parcel	Apr. 02, 2014 Allotment_Parcel	Apr. 01, 2014 USD ($)	Jan. 06, 2014 Allotment_Parcel	Sep. 30, 2012 Allotment_Parcel
Continuous Highwall Mining [Member] | San Juan Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
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		$ 5.0
Public Utilities, PNM Share Estimated Underpaid Surface Mining Royalties under proposed rate change		46.30%
NMTRD Coal Severance Tax [Member] | Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Assessed Coal Severance Surtax Penalty and Interest		$ 30.0
Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Ownership Percentage in Nuclear Reactor		10.20%
Public Utilities, Maximum Potential Assessment Per Incident		$ 38.9
Public Utilities, Annual Payment Limitation Related to Incident		5.7
Public Utilities, Aggregate Amount of All Risk Insurance		2,750.0
Public Utilities, Maximum Amount under Nuclear Electric Insurance Limited		5.4
Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member] | Maximum [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Liability Insurance Coverage		13,400.0
Public Utilities, Liability Insurance Coverage Sublimit					$ 2,250.0
Public Service Company of New Mexico [Member] | Commercial Providers [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Liability Insurance Coverage		375.0
Public Service Company of New Mexico [Member] | Industry Wide Retrospective Assessment Program [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Liability Insurance Coverage		$ 13,000.0
Public Service Company of New Mexico [Member] | NMTRD Coal Severance Tax [Member] | Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, PNM Share Assessed Coal Severance Surtax Penalty and Interest to pass through FFPAC		9.40%
Public Service Company of New Mexico [Member] | Navajo Nation Allottee Matters [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Number of landowners claiming to be Navajo allottees | Allotment_Parcel							43
Number of allotment parcels' appraisal requested for review | Allotment_Parcel						58
Number of allotments where landowners are revoking rights of way renewal consents | Allotment_Parcel			10	6
Public Service Company of New Mexico [Member] | Navajo Nation Allottee Matters [Member] | Subsequent Event [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Area of Land | a	15.49

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Variable Interest Entities

6 Months Ended

Jun. 30, 2015

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 2014 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, 2015, PNM paid $4.8 million and $9.6 million for fixed charges and $0.5 million and $0.6 million for variable charges. 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. 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,
	2015			2014			2015			2014
	(In thousands)
Operating revenues	$	5,251		$	5,307		$	10,155		$	10,238
Operating expenses	(1,401		)	(1,399		)	(2,924		)	(2,799		)
Earnings attributable to non-controlling interest	$	3,850		$	3,908		$	7,231		$	7,439

Financial Position

	June 30,		December 31,
	2015		2014
	(In thousands)
Current assets	$	3,284	$	2,513
Net property, plant, and equipment	71,180		72,321
Total assets	74,464		74,834
Current liabilities	1,301		1,288
Owners’ equity – non-controlling interest	$	73,163	$	73,546

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 NMPRC and FERC would be required, which could take up to 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. The owner of Valencia subsequently submitted a counter-proposal to PNM in April 2015. PNM is evaluating the terms of the counter-proposal. 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 provided 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 provided PNM with options to renew the leases at fixed rates set forth in the leases for 2 years beyond the termination of the original lease terms. The option periods on certain leases could be further extended for up to an additional 6 years if the appraised remaining useful lives and fair value of the leased assets were greater than parameters set forth in the leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and Note 6 for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities.

PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments. As of June 30, 2015, these 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 $150.5 million, including the renewal terms of the leases that PNM has 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, 2015, PNM could have been required to pay the beneficial owners up to $217.3 million on July 15, 2015 in addition to the regularly scheduled lease payments. In such event, PNM would record the acquired assets at the lower of their fair value or the aggregate of the amount paid and PNM’s carrying value of its investment in PVNGS lessor notes. 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 no assets or liabilities recorded on its Condensed Consolidated Balance Sheets related to the trusts other than accrued lease payments of $18.4 million at June 30, 2015 and $26.0 million at December 31, 2014, which are included in other current liabilities on the Condensed Consolidated Balance Sheets.

PNM has evaluated the PVNGS lease arrangements, including actions taken with respect to renewal and purchase options, 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.

Rio Bravo, formerly known as Delta

PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which was a variable interest under GAAP. PNM controlled the dispatch of the generating plant, which impacted the variable payments made under the PPA and impacted the economic performance of the entity that owned Delta. This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it was the primary beneficiary of the entity that owned Delta, or to consolidate that entity if it were determined that PNM was the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.

In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owned Delta. PNM closed on the purchase on July 17, 2014 and recorded the purchase as of that date. PNM changed the name of the facility to Rio Bravo.

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. PNM recovered the variable energy charges through its FPPAC. Delta informed PNM that for the three and six months ended June 30, 2014 its revenue was $2.5 million and $4.3 million and its net earnings were $0.3 million and $0.6 million.

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

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Lease Commitments

6 Months Ended

Jun. 30, 2015

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, through April 1, 2015, an interest in the EIP transmission line. All of the Company’s leases are accounted for as operating leases. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K, including information regarding renewal and purchase options, and actions taken by PNM under the PVNGS leases.

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. The four Unit 1 leases have been extended to expire on January 15, 2023 and one of the Unit 2 leases has been extended to expire on January 15, 2024. For the other three PVNGS Unit 2 leases, PNM elected to purchase the assets underlying those leases on the expiration date of the original leases and has entered into agreements with the lessors that establish the purchase prices, representing the fair market value, to be paid on January 15, 2016 by PNM for the assets underlying the leases. The leases remain in existence and PNM will record the purchases at the termination of the leases on January 15, 2016.

PNM will pay $78.1 million for the assets underlying one of the Unit 2 leases, which is for 31.25 MW of the entitlement from PVNGS Unit 2. PNM will pay $85.2 million for the assets underlying the other two Unit 2 leases, which are for 32.76 MW of the entitlement from PVNGS Unit 2. PNMR Development is also a party to the agreement regarding these two leases, 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, $83.4 million on June 30, 2015, 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, $2.8 million on June 30, 2015, and declines to $1.2 million on January 14, 2016. Currently, PNMR does not anticipate that PNMR Development will exercise the early purchase option.

At March 31, 2015, PNM owned 60% of the EIP and leased the other 40%, under a lease that expired on April 1, 2015. Following procedures set forth in the lease, PNM and the lessor entered into a definitive agreement for PNM to exercise its option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. PNM closed on the purchase on April 1, 2015 and recorded the purchase at that date.

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Stock-Based Compensation

6 Months Ended

Jun. 30, 2015

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”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. 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. 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 2014 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 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, 2015 and December 31, 2014, PNMR had unrecognized expense related to stock awards of $7.8 million and $6.5 million. 

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 grant date fair value for other restricted stock awards 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 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	2015			2014
Expected quarterly dividends per share	$	0.200		$	0.185
Risk-free interest rate	0.92		%	0.62		%
Market-Based Shares
Dividend yield	2.87		%	2.82		%
Expected volatility	18.73		%	25.11		%
Risk-free interest rate	1.00		%	0.64		%

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, 2015:

	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2014	258,770		$	22.31	920,505		$	20.39
Granted	340,020		$	20.34	—		$	—
Exercised	(348,095	)	$	18.59	(210,945	)	$	20.07
Forfeited	—		$	—	(1,000	)	$	30.50
Expired	—		$	—	(66,201	)	$	27.90
Outstanding at June 30, 2015	250,695		$	24.82	642,359		$	19.51

PNMR’s stock-based compensation program provides for performance and market targets through 2017. Included as granted and exercised in the above table are 179,845 previously awarded shares that were earned for the 2012 through 2014 performance measurement period and approved by the Board in February 2015 (based upon achieving market targets at “target” levels, weighted at 60%, and performance targets at “maximum” levels, weighted at 40%). Excluded from the above table, are maximums of 180,970, 165,628, and 168,258 shares for the three-year performance periods ending in 2015, 2016, and 2017 that would be awarded if all performance and market criteria are achieved at maximum levels 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 PNMR meets specific market targets at the end of 2016 and she remains an employee of the Company. Under the agreement, she would receive 35,000 of the total shares if PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2014 and the Board approved her receiving the 35,000 shares in February 2015, which shares are included as granted and exercised in the above table. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2016, he would receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. If the target for the first performance period is not met, but the target for the second performance period is met, he would receive both awards, less any amount received previously under the agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include any restricted stock shares under this retention award agreement.

In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she would receive 17,953 of the total shares if PNMR achieves specific performance targets at the end of 2017. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include any restricted stock shares under this retention award agreement.

At June 30, 2015, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $4.7 million with a weighted-average remaining contract life of 2.62 years. At June 30, 2015, the exercise price of 245,950 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,
Restricted Stock	2015		2014
Weighted-average grant date fair value	$	20.34	$	21.27
Total fair value of restricted shares that vested (in thousands)	$	6,470	$	4,854
Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	—
Total intrinsic value of options exercised (in thousands)	$	1,759	$	1,779

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Regulatory and Rate Matters - Integrated Resource Plan, Four Corners Right of First Refusal and Application for Certificate (Details) - Public Service Company of New Mexico [Member] $ in Millions	1 Months Ended	3 Months Ended	4 Months Ended
	Jul. 31, 2011	Jun. 30, 2015 USD ($) MW	Jun. 17, 2015	Feb. 17, 2015
Four Corners [Member]
Public Utilities, General Disclosures [Line Items]
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities				7.00%
Period of time to file a waiver of rights of first refusal			120 days
San Juan Generating Station Units 2 and 3 [Member] | Clean Air Act, SNCR [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Newly Identified Replacement Gas-fired Generation, in Megawatts | MW		187
Public Utilities, Cost of replacement gas-generation		$ 133.2
Integrated Resource Plan, 2011 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Frequency of IRP filings		3 years
Public Utilities, Planning Period Covered of IRP	20 years

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Regulatory and Rate Matters - Firm-Requirements Wholesale Customers (Details) - Public Service Company of New Mexico [Member] $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Dec. 31, 2014 USD ($) MW
Firm Requirements Wholesale Power Rate Case, Navopache [Member] [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 5.3
Public Utilities, Average monthly usage in megawatts | MW			55
Public Utilities, Revenue For Power Sold Under Specific Contract			$ 28.4
Firm Requirements Wholesale Power Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Contract Extension		10 years
City of Gallup, New Mexico Contract [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revenue For Power Sold Under Specific Contract		$ 6.1
Public Utilities, Gain on sale of substation	$ 1.1

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Regulatory and Rate Matters - Energy Efficiency and Load Management (Details) - Public Service Company of New Mexico [Member] - USD ($) $ in Millions		6 Months Ended
	Oct. 06, 2014	Jun. 30, 2015	Dec. 31, 2014
Energy Efficiency and Load Management [Member] | Disincentives / Incentives Adder [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Program Costs Related To Energy Efficiency	$ 25.8
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		$ 1.7
Public Utilities, Proposed Profit Incentive Adder Revenues Related To 2015 Energy Efficiency Program	$ 2.1
2014 Energy Efficiency and Load Management Program [Member] | Disincentives / Incentives Adder [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Anticipated future profit incentive 2015			$ 1.7
Public Utilities, Anticipated future profit incentive 2016			$ 1.8
Maximum [Member] | Renewable Portfolio Standard [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Reasonable Cost Threshold		3.00%

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2015

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

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,
	2015		2014		2015		2014
	(In thousands)
Services billings:
PNMR to PNM	$	21,340	$	22,190	$	44,067	$	43,256
PNMR to TNMP	6,591		6,963		13,680		14,224
PNM to TNMP	184		133		288		242
TNMP to PNMR	—		—		—		—
Interest billings:
PNMR to TNMP	54		83		133		180
PNMR to PNM	22		—		28		54
PNM to PNMR	26		25		55		51
Income tax sharing payments:
PNMR to PNM	—		—		1,450		—
PNMR to TNMP	—		—		—		—

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Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
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	7,064	7,541	14,127	15,082
Expected return on plan assets	(9,831)	(9,511)	(19,662)	(19,022)
Amortization of net (gain) loss	3,705	3,255	7,410	6,510
Amortization of prior service cost	(241)	(241)	(483)	(483)
Net Periodic Benefit Cost (Income)	697	1,044	1,392	2,087
Defined Benefit Plan, Contributions by Employer	0	0	30,000	0
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	0		0
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	22,000		$ 22,000
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)			4.80%
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	51	45	$ 102	91
Interest cost	1,023	1,159	2,045	2,315
Expected return on plan assets	(1,403)	(1,410)	(2,805)	(2,819)
Amortization of net (gain) loss	491	556	983	1,113
Amortization of prior service cost	(160)	(336)	(321)	(672)
Net Periodic Benefit Cost (Income)	2	14	4	28
Defined Benefit Plan, Contributions by Employer	800	800	1,600	1,600
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	3,500		3,500
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	14,000		14,000
Public Service Company of New Mexico [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	190	205	380	411
Expected return on plan assets	0	0	0	0
Amortization of net (gain) loss	81	52	162	105
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	271	257	542	516
Defined Benefit Plan, Contributions by Employer	400	400	900	700
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	1,500		1,500
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	761	798	1,521	1,597
Expected return on plan assets	(1,105)	(1,132)	(2,210)	(2,263)
Amortization of net (gain) loss	195	166	391	333
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	(149)	(168)	(298)	(333)
Defined Benefit Plan, Contributions by Employer	0	0	0	0
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	0		0
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	$ 0		0
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)	4.80%
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	$ 62	59	124	119
Interest cost	152	155	304	309
Expected return on plan assets	(130)	(133)	(260)	(267)
Amortization of net (gain) loss	0	(31)	0	(61)
Amortization of prior service cost	0	8	0	16
Net Periodic Benefit Cost (Income)	84	58	168	116
Defined Benefit Plan, Contributions by Employer	0	300	0	300
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	300		300
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	1,400		1,400
Texas-New Mexico Power Company [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	9	10	18	20
Expected return on plan assets	0	0	0	0
Amortization of net (gain) loss	1	0	2	0
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	10	10	20	20
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	100		100
Texas-New Mexico Power Company [Member] | Other Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Contributions by Employer	$ 100	$ 100	$ 100	$ 100

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Income Taxes

6 Months Ended

Jun. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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 is being 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. 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 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. 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, 2015 and 2014, PNM’s regulatory liability was reduced by $2.0 million and $4.6 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment; and were reduced by $0.2 million in the three months ended March 31, 2014 increasing income tax expense in the Corporate and Other segment.

In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008. 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.

On December 19, 2014, the Tax Increase Prevention Act of 2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law.  Due to provisions in the act, taxes payable to the State of New Mexico were reduced. The act resulted in an impairment of New Mexico net operating loss carryforwards, which was recorded as additional income tax expense during the year ended December 31, 2014. During the three months ended March 31, 2015, the impairment of the New Mexico net operating loss carryforward was refined, resulting in an additional impairment of $1.0 million, after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. TNMP had no such impairment.

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2015

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, 2015
Electric operating revenues	$	275,450		$	77,437		$	—		$	352,887
Cost of energy	95,728			18,310			—			114,038
Margin	179,722			59,127			—			238,849
Other operating expenses	103,541			20,807			(3,962		)	120,386
Depreciation and amortization	29,002			13,591			3,456			46,049
Operating income (loss)	47,179			24,729			506			72,414
Interest income	1,946			—			(5		)	1,941
Other income (deductions)	7,446			793			(673		)	7,566
Net interest charges	(19,681		)	(6,856		)	(2,376		)	(28,913		)
Segment earnings (loss) before income taxes	36,890			18,666			(2,548		)	53,008
Income taxes (benefit)	11,527			6,801			(975		)	17,353
Segment earnings (loss)	25,363			11,865			(1,573		)	35,655
Valencia non-controlling interest	(3,850		)	—			—			(3,850		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	21,381		$	11,865		$	(1,573	)	$	31,673
Six Months Ended June 30, 2015
Electric operating revenues	$	537,390		$	148,365		$	—		$	685,755
Cost of energy	193,594			36,089			—			229,683
Margin	343,796			112,276			—			456,072
Other operating expenses	207,557			42,567			(7,546		)	242,578
Depreciation and amortization	57,405			27,049			7,056			91,510
Operating income	78,834			42,660			490			121,984
Interest income	3,717			—			(26		)	3,691
Other income (deductions)	13,257			2,084			(2,452		)	12,889
Net interest charges	(39,640		)	(13,781		)	(5,765		)	(59,186		)
Segment earnings (loss) before income taxes	56,168			30,963			(7,753		)	79,378
Income taxes (benefit)	17,302			11,404			(2,836		)	25,870
Segment earnings (loss)	38,866			19,559			(4,917		)	53,508
Valencia non-controlling interest	(7,231		)	—			—			(7,231		)
Subsidiary preferred stock dividends	(264		)	—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	31,371		$	19,559		$	(4,917	)	$	46,013
At June 30, 2015:
Total Assets	$	4,544,279		$	1,268,862		$	113,877		$	5,927,018
Goodwill	$	51,632		$	226,665		$	—		$	278,297

	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

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Financing - Financing Activities (Details) - USD ($) $ in Thousands		12 Months Ended
	May. 08, 2015	Dec. 31, 2014	Jun. 30, 2015	Jun. 01, 2015	Mar. 09, 2015	Dec. 22, 2014	Mar. 05, 2014	Apr. 22, 2013
Debt Instrument [Line Items]
Short-term debt		$ 105,600	$ 187,600
PNMR 2015 Term Loan Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt					$ 150,000
Debt Instrument, Interest Rate at Period End			1.19%
Public Service Company of New Mexico [Member] | PNM 2014 Term Loan Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt							$ 175,000
Debt Instrument, Interest Rate at Period End			1.14%
Public Service Company of New Mexico [Member] | PNM 2014 Multi-Draw Term Loan Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt			$ 125,000			$ 125,000
Debt Instrument, Interest Rate at Period End			0.77%
Proceeds from (Repayments of) Debt	$ 25,000	100,000
PNM Term Loan Agreement [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Short-term debt								$ 75,000
Senior unsecured note, due 2015, at 9 point 25 percent [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent		$ 118,800
Debt Instrument, Interest Rate, Stated Percentage		9.25%
Senior unsecured note, PCRB Due 2043, at 4 percent [Member] | Public Service Company of New Mexico [Member] | Unsecured notes, Pollution control revenue bonds [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent		$ 39,300
Debt Instrument, Interest Rate, Stated Percentage				2.40%
Senior unsecured note, PCRB Due 2043, at 2 point 4 percent [Member] | Public Service Company of New Mexico [Member] | Unsecured notes, Pollution control revenue bonds [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent				$ 39,300

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Fair Value of Derivative and Other Financial Instruments - Derivative Balance Sheet Information (Details) - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Current assets	$ 4,550,000	$ 11,232,000
Commodity derivative instruments, Current liabilities	(1,153,000)	(1,209,000)
Commodity derivative instruments, Long-term liabilities	0	(477,000)
Assets, Current	410,065,000	432,817,000
PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Derivative, Collateral, Right to Reclaim Cash	0	0
Margin Deposit Assets	1,600,000	3,800,000
Derivative, Collateral, Obligation to Return Cash	200,000	200,000
Fair Value Hedging [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Current assets	4,550,000	11,232,000
Commodity derivative instruments, Assets	4,550,000	11,232,000
Commodity derivative instruments, Current liabilities	(1,153,000)	(1,209,000)
Commodity derivative instruments, Long-term liabilities	0	(477,000)
Commodity derivative instruments, Liabilities	(1,153,000)	(1,686,000)
Commodity derivative instruments, Net	3,397,000	9,546,000
Fair Value Hedging [Member] | Commodity Contract [Member] | Fuel and Purchased Power Adjustment Clause [Member] | Public Service Company of New Mexico [Member] | Maximum [Member]
Derivatives, Fair Value [Line Items]
Assets, Current	100,000	0
Fair Value Hedging [Member] | Commodity Contract [Member] | Palo Verde Nuclear Generating Station [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Current assets	$ 1,500,000	$ 3,000,000

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Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash Flows From Operating Activities:
Net Earnings	$ 53,508	$ 49,312
Net earnings	46,013	41,609
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	108,891	103,436
Deferred income tax expense	26,675	24,252
Net unrealized (gains) losses on commodity derivatives	6,127	3,187
Realized (gains) on available-for-sale securities	(9,580)	(7,272)
Stock based compensation expense	2,761	3,399
Regulatory disallowances	1,744	0
Other, net	(1,926)	38
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(20,899)	(17,543)
Materials, supplies, and fuel stock	(8,285)	6,346
Other current assets	16,342	(20,688)
Other assets	8,062	18,237
Accounts payable	(20,777)	(29,384)
Accrued interest and taxes	(4,380)	(2,830)
Other current liabilities	(10,195)	(3,341)
Other liabilities	(38,394)	(3,343)
Net cash flows from operating activities	109,674	123,806
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(232,964)	(160,893)
Proceeds from sales of available-for-sale securities	94,522	53,119
Purchases of available-for-sale securities	(94,905)	(54,338)
Return of principal on PVNGS lessor notes	14,188	10,231
Other, net	2,694	750
Net cash flows from investing activities	(216,465)	(151,131)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	82,000	(44,200)
Long-term borrowings	214,300	255,000
Repayment of long-term debt	(158,066)	(125,000)
Proceeds from stock option exercise	7,347	4,446
Awards of common stock	(18,814)	(13,939)
Dividends paid	(32,125)	(29,732)
Valencia’s transactions with its owner	(7,614)	(8,189)
Other, net	(2,107)	(1,482)
Net cash flows from financing activities	84,921	36,904
Change in Cash and Cash Equivalents	(21,870)	9,579
Cash and Cash Equivalents at Beginning of Period	28,274	2,533
Cash and Cash Equivalents at End of Period	6,404	12,112
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	56,309	54,712
Income taxes paid (refunded), net	(1,231)	(2,534)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	(743)	(7,909)
Public Service Company of New Mexico [Member]
Cash Flows From Operating Activities:
Net Earnings	38,866	35,460
Net earnings	31,635	28,021
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	73,701	71,327
Deferred income tax expense	18,464	19,716
Net unrealized (gains) losses on commodity derivatives	6,127	3,187
Realized (gains) on available-for-sale securities	(9,580)	(7,272)
Regulatory disallowances	1,744	0
Other, net	(2,958)	193
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(15,283)	(13,885)
Materials, supplies, and fuel stock	(7,860)	6,447
Other current assets	15,882	(22,588)
Other assets	7,568	18,790
Accounts payable	(21,315)	(26,737)
Accrued interest and taxes	412	(1,575)
Other current liabilities	(3,259)	3,943
Other liabilities	(34,729)	(3,193)
Net cash flows from operating activities	67,780	83,813
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(172,937)	(92,567)
Proceeds from sales of available-for-sale securities	94,522	53,119
Purchases of available-for-sale securities	(94,905)	(54,338)
Return of principal on PVNGS lessor notes	14,188	10,231
Other, net	2,859	(70)
Net cash flows from investing activities	(156,273)	(83,625)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	51,100	(49,200)
Short-term borrowings (repayments), affiliate, net	0	(32,500)
Long-term borrowings	64,300	175,000
Repayment of long-term debt	(39,300)	(75,000)
Dividends paid	(264)	(264)
Valencia’s transactions with its owner	(7,614)	(8,189)
Other, net	(1,659)	(700)
Net cash flows from financing activities	66,563	9,147
Change in Cash and Cash Equivalents	(21,930)	9,335
Cash and Cash Equivalents at Beginning of Period	25,480	21
Cash and Cash Equivalents at End of Period	3,550	9,356
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	36,977	36,601
Income taxes paid (refunded), net	(1,450)	(215)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	(2,813)	(5,595)
Texas-New Mexico Power Company [Member]
Cash Flows From Operating Activities:
Net Earnings	19,559	16,336
Net earnings	19,559	16,336
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	27,839	25,728
Deferred income tax expense	6,175	6,162
Other, net	(90)	(38)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(5,616)	(3,658)
Materials, supplies, and fuel stock	(425)	(101)
Other current assets	(1,264)	(803)
Other assets	68	(273)
Accounts payable	385	1,381
Accrued interest and taxes	(173)	(726)
Other current liabilities	2,530	2,167
Other liabilities	(4,132)	365
Net cash flows from operating activities	44,856	46,540
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(50,256)	(64,502)
Net cash flows from investing activities	(50,256)	(64,502)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	24,000	0
Short-term borrowings (repayments), affiliate, net	(18,600)	(4,200)
Long-term borrowings	0	80,000
Repayment of long-term debt	0	(50,000)
Dividends paid	0	(6,803)
Other, net	0	(783)
Net cash flows from financing activities	5,400	18,214
Change in Cash and Cash Equivalents	0	252
Cash and Cash Equivalents at Beginning of Period	1	1
Cash and Cash Equivalents at End of Period	1	253
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	12,990	11,847
Income taxes paid (refunded), net	950	(304)
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	$ (2,311)	$ (1,038)

XML

Earnings Per Share

6 Months Ended

Jun. 30, 2015

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,
	2015		2014		2015		2014
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	31,673	$	29,141	$	46,013	$	41,609
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	99		110		105		146
Average Shares – Basic	79,753		79,764		79,759		79,800
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	380		464		384		508
Average Shares – Diluted	80,133		80,228		80,143		80,308
Net Earnings Per Share of Common Stock:
Basic	$	0.40	$	0.37	$	0.58	$	0.52
Diluted	$	0.40	$	0.36	$	0.57	$	0.52

⁽¹⁾  Excludes the effect of out-of-the-money options for 245,950 shares of common stock at June 30, 2015.

XML

Commitments and Contingencies - Litigation and Rulemaking (Details) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Dec. 21, 2011 mw
Public Utilities, Commitments And Contingencies [Line Items]
Minimum Megawatt Capacity from Coal and Oil-Fired Electric Generating Units under Jurisdiction of the Mercury and Air Toxics Standards | mw			25
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Mercury Removal Rate, Percentage	99.00%	99.00%
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Mercury Control [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Current Annual Mercury Control Costs		$ 0.7
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Maximum [Member] | Mercury Control [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Contingent Estimated Annual Mercury Control Cost		$ 6.6
Public Service Company of New Mexico [Member] | Four Corners Units 4 and 5 (Coal) [Member] | Clean Air Act Lawsuit [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Litigation Settlement, Amount	$ 1.5
Litigation settlement, expected capital spend, environmental	$ 6.2
Public Utilities, Ownership Percentage	13.00%	13.00%

XML

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Tax Contingency [Line Items]
Decrease in regulatory liabilities due to change in state corporate tax rate		$ 2,000		$ 4,600
Decrease in deferred tax asset due to change in state corporate tax rate				$ 200
Income Taxes	$ 17,353		$ 15,893		$ 25,870	$ 22,313
State Net Operating Loss Carryforward, Impairment		1,000
Public Service Company of New Mexico [Member]
Income Tax Contingency [Line Items]
Increase in deferred tax asset not related to regulatory activity, as a result of tax rate change		700
Decrease in income tax expense due to tax rate change		500
Income Taxes	11,527		13,106		17,302	17,189
State Net Operating Loss Carryforward, Impairment		700
Corporate and Other [Member]
Income Tax Contingency [Line Items]
Decrease in income tax expense due to tax rate change		200
Income Taxes	$ (975)		(2,803)		$ (2,836)	(4,516)
State Net Operating Loss Carryforward, Impairment		$ 300
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Income Taxes			1,300
PNM Resources [Member] | Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority			2,000			$ 2,000
Income Taxes			200
Public Service Company of New Mexico [Member] | Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Income Taxes			1,100
Texas-New Mexico Power Company [Member] | Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Income Taxes			$ 0

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Accumulated Other Comprehensive Income (Loss) (Tables)

6 Months Ended

Jun. 30, 2015

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the six months ended June 30, 2015 and 2014 is as follows:

	Accumulated Other Comprehensive Income (Loss)
	PNM									TNMP		PNMR
	Unrealized									Fair Value
	Gain on			Pension						Adjustment
	Available-for-			Liability						for Cash Flow
	Sale Securities			Adjustment			Total			Hedges		Total
	(In thousands)
Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—	$	(61,755	)
Amounts reclassified from AOCI (pre-tax)	(12,537		)	2,976			(9,561		)	—		(9,561		)
Income tax impact of amounts reclassified	4,913			(1,166		)	3,747			—		3,747
Other OCI changes (pre-tax)	6,157			—			6,157			—		6,157
Income tax impact of other OCI changes	(2,413		)	—			(2,413		)	—		(2,413		)
Net change after income taxes	(3,880		)	1,810			(2,070		)	—		(2,070		)
Balance at June 30, 2015	$	24,128		$	(87,953	)	$	(63,825	)	$	—	$	(63,825	)

Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(57,877	)	$	(263	)	$	(58,140	)
Amounts reclassified from AOCI (pre-tax)	(8,857		)	2,576			(6,281		)	176			(6,105		)
Income tax impact of amounts reclassified	3,488			(1,016		)	2,472			(61		)	2,411
Other OCI changes (pre-tax)	9,855			—			9,855			(153		)	9,702
Income tax impact of other OCI changes	(3,809		)	—			(3,809		)	53			(3,756		)
Net change after income taxes	677			1,560			2,237			15			2,252
Balance at June 30, 2014	$	26,425		$	(82,065	)	$	(55,640	)	$	(248	)	$	(55,888	)

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Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Equity [Abstract]
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process			23.00%	23.00%
Percentage of Pension Liability Adjustment Capitalized into Other Accounts			2.70%	2.10%
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			$ (61,755)
Net change after income taxes	$ (4,595)	$ 1,461	(2,070)	$ 2,252
Ending Balance	(63,825)		(63,825)
PNMR and PNM [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			28,008	25,748
Amounts reclassified from AOCI (pre-tax)			(12,537)	(8,857)
Income tax impact of amounts reclassified			4,913	3,488
Other OCI changes (pre-tax)			6,157	9,855
Income tax impact of other OCI changes			(2,413)	(3,809)
Net change after income taxes			(3,880)	677
Ending Balance	24,128	26,425	24,128	26,425
PNMR and PNM [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(89,763)	(83,625)
Amounts reclassified from AOCI (pre-tax)			2,976	2,576
Income tax impact of amounts reclassified			(1,166)	(1,016)
Net change after income taxes			1,810	1,560
Ending Balance	(87,953)	(82,065)	(87,953)	(82,065)
PNM [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(61,755)	(57,877)
Amounts reclassified from AOCI (pre-tax)			(9,561)	(6,281)
Income tax impact of amounts reclassified			3,747	2,472
Other OCI changes (pre-tax)			6,157	9,855
Income tax impact of other OCI changes			(2,413)	(3,809)
Net change after income taxes			(2,070)	2,237
Ending Balance	(63,825)	(55,640)	(63,825)	(55,640)
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)
Amounts reclassified from AOCI (pre-tax)				176
Income tax impact of amounts reclassified				(61)
Other OCI changes (pre-tax)				(153)
Income tax impact of other OCI changes				53
Net change after income taxes				15
Ending Balance		(248)		(248)
PNMR [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance			(61,755)	(58,140)
Amounts reclassified from AOCI (pre-tax)			(9,561)	(6,105)
Income tax impact of amounts reclassified			3,747	2,411
Other OCI changes (pre-tax)			6,157	9,702
Income tax impact of other OCI changes			(2,413)	(3,756)
Net change after income taxes			(2,070)	2,252
Ending Balance	$ (63,825)	$ (55,888)	$ (63,825)	$ (55,888)

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Regulatory and Rate Matters

6 Months Ended

Jun. 30, 2015

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 2014 Annual Reports on Form 10-K.

PNM

2014 Electric Rate Case

On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future test year (“FTY”) period. The application proposed a revenue increase of $107.4 million, effective January 1, 2016. PNM’s proposed ROE was 10.5%. The requested base rate increase, combined with other rate changes, represented an average bill increase of 7.69%. PNM requested this increase to account for infrastructure investments made since the last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect the declining sales growth in PNM’s service territory. The primary driver of PNM’s identified revenue deficiency, accounting for approximately 92% of the rate increase, was related to infrastructure investments and the recovery of those investment dollars, including depreciation. PNM’s success with energy efficiency programs was a contributing factor to the decline in PNM’s energy sales since the last rate case and accounted for the balance of the rate increase after accounting for offsetting cost reductions. PNM proposed several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals included increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, an access charge to customers installing distributed generation systems after December 31, 2015, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. Several parties filed briefs, which alleged that PNM’s application was incomplete and challenged the distributed generation charge, as well as other aspects of PNM’s filing. PNM filed a response brief addressing these matters.

On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it on the grounds that it does not comply with the FTY rule. The Hearing Examiner cited procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. The Hearing Examiner recommended that PNM be granted the ability to keep the calendar year 2016 future test period and that PNM could reapply for a general rate increase by remedying the files and providing other supporting documents. PNM did not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argued that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision established an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullified the future test year statute.  PNM further argued that its application should be suspended, rather than dismissed. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision regarding the completeness of PNM’s application and dismissed PNM’s application. This NMPRC order did not address the Hearing Examiner’s recommendation regarding when a future test period could begin relative to a rate case application date.

On May 27, 2015, the NMPRC approved an order that defines a FTY as a period that begins no later than 45 days following the filing of an application to increase rates. PNM disagrees with the interpretation adopted by the NMPRC and believes that the correct interpretation of the New Mexico FTY statute allows a FTY to begin up to 13 months after the filing of an application.

On June 25, 2015, PNM filed a Notice of Appeal to the New Mexico Supreme Court, challenging the NMPRC’s June 3, 2015 written order. There is no required timeframe for the New Mexico Supreme Court to act on PNM’s appeal. Two other utilities have filed separate notices of appeals with the Supreme Court and ABCWUA filed a notice of cross appeal. On July 15, 2015, the NMPRC filed its Motion for Stay of Proceeding at Supreme Court and for Remand of Jurisdiction, seeking the ability to conduct a rulemaking process on the definition and parameters of a FTY for rate cases. PNM opposes the motion. Responses to the motion are due August 17, 2015. On July 31, 2015, PNM and the NMPRC filed a joint motion for a limited 30-day stay and remand of PNM’s appeal so that the NMPRC can reconsider its FTY order in PNM’s 2014 rate case; this motion is opposed by ABCWUA.

Based on the above NMPRC rulings, PNM currently anticipates filing, in the third quarter of 2015, a new application with the NMPRC to increase rates. The contemplated rate request would be updated to include current circumstances. New rates would be expected to become effective in the third quarter of 2016.

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, which are subject to the limitation of the RCT, are 30% wind, 20% solar, 5% other, and 3% distributed generation.

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.

PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements included 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. The NMPRC approved the plan on December 18, 2013. PNM made procurements in 2014 consistent with the approved plan. Construction of the solar PV facilities was completed in 2014 at a cost of $46.5 million.

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 included 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). A stipulated settlement was approved by the NMPRC on November 26, 2014. Under the agreement, the costs of the 40 MW of solar would be included in base rates rather than through PNM’s renewable energy rider and have been included in rates requested in the 2014 Electric Rate Case discussed above. In addition, PNM would be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT at a not-to-exceed price of $3.00 per MWh in 2013 and 2014. In the fourth quarter of 2014 and the second quarter of 2015, PNM procured the additional renewable resources to meet the 2013 and 2014 RPS requirement for $0.1 million and less than $0.1 million. The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans.

PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan meets RPS and diversity requirements within the RCT in 2016 and 2017. The plan does not propose any significant new procurements. A public hearing on the 2016 procurement plan is scheduled to begin on September 1, 2015 and an order from the NMPRC is expected by November 30, 2015.

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 electric 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. PNM made filings with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013 and 2014 on April 1, 2014 and April 1, 2015. PNM recorded revenues from the rider of $34.3 million in 2014. In PNM’s 2015 renewable energy procurement plan case, the NMPRC approved a rate, which is designed to collect $44.7 million in 2015. On February 27, 2015, PNM filed a notice to reduce the amount to be collected during 2015 to $43.0 million, reflecting a reconciliation of expenses and revenues under the rider during 2014 and updated cost estimates for 2015. The rate reduction was due to an over-collection in 2014 that primarily resulted from lower than projected generation of geothermal renewable energy. The revision was implemented on April 27, 2015. PNM proposes to recover $42.4 million through the rider in 2016 in its 2016 renewable energy procurement plan.

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. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s 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.

On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. PNM and the NMPRC staff filed a stipulation on January 30, 2015. A public hearing on the stipulation was held in February 2015. The Hearing Examiner issued a Certification of Stipulation on April 10, 2015 recommending that the NMPRC approve the stipulation in its entirety and to allow PNM to continue recovering the incentive contemporaneously with program costs. On April 29, 2015, the NMPRC approved the certification. Upon approval, the stipulation established program budgets and the incentive amounts discussed below.

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

In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million. PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. Under the terms of the January 30, 2015 stipulation discussed above, the incentive amount would be $1.7 million in 2015 and $1.8 million in 2016 assuming threshold level of savings are achieved.

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. The NMPRC issued an order on October 8, 2014 adopting the proposed rule, which includes a provision that limits incentive awards to an amount equal to the utility’s WACC times its approved annual program costs.

Integrated Resource Plan

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3.

San Juan Generating Station Units 2 and 3 Retirement

On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommends rejection of the agreement as proposed, and recommended several modifications to the agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation and certification, is set forth in Note 11. PNM anticipates an order from the NMPRC in the fourth quarter of 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 February 17, 2015, PNM received notice from EPE that EPE has entered into an agreement to sell its 7% interest in Four Corners to APS, thereby triggering PNM’s ability to exercise its right of first refusal (“ROFR”) to acquire a portion of EPE’s interest in Four Corners. PNM notified the NMPRC about receipt of the notice and advised the NMPRC that PNM does not intend to exercise its rights under the ROFR. The ROFR expired unexercised 120 days from the date of the notice.

Application for Certificate of Convenience and Necessity

On June 30, 2015, PNM filed an application for a CCN for a 187 MW gas plant to be located at SJGS. This resource was identified as a replacement resource in PNM’s application to retire SJGS Units 2 and 3. PNM estimates the cost of the facility to be $133.2 million. PNM identified the necessary in-service date to be in the first half of 2018. On July 9, 2015, a party filed a motion to consolidate this case with the SJGS Unit 2 and 3 retirement case. The NMPRC has not yet acted on PNM’s application or on the motion. PNM cannot predict the outcome of this proceeding.

Formula Transmission Rate Case

In a settlement of a prior rate case for PNM’s transmission customers, the parties agreed that if PNM filed for a formula based rate change, no party would oppose the general principle of a formula rate, although the parties could object to particular aspects of the formula. 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. The 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 approved in the previous rate case. The new rates apply to all of PNM’s wholesale electric transmission service customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates on April 1, 2015, subject to refund. There is no required time frame for FERC to act upon the settlement.

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc.

In September 2011, PNM filed an unexecuted amended power sales agreement (“PSA”) between PNM and NEC with FERC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and amended PSA, which were filed with FERC on December 6, 2012. The settlement agreement and amended PSA provided for an annual increase in revenue of $5.3 million and an extension of the contract for 10 years through December 31, 2035. On April 5, 2013, FERC approved the settlement agreement and the amended PSA. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement.

On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under the amended PSA. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both the intent of the amended PSA for PNM to supply NEC’s long-term power requirements and the amended PSA’s provision that expressly disallows termination of the agreement before December 31, 2035. NEC has asked for FERC to act on the petition by September 30, 2015. On May 8, 2015, PNM filed an intervention with FERC requesting that FERC deny NEC’s petition or to proceed with a public hearing if the petition is not denied. On July 16, 2015, FERC issued an order setting the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA, and holding the hearing in abeyance to provide time for settlement judge procedures, which have begun. PNM is unable to predict the outcome of this matter.

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 September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility.  PNM’s contract with Gallup ended on June 29, 2014.  PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014. PNM’s 2014 Electric Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.

In conjunction with the termination of PNM’s electric service agreement with Gallup, Gallup purchased substations and associated transmission facilities owned by PNM that had been used solely to provide service to Gallup. This sale resulted in a gain of $1.1 million, which PNM recorded in other income during the three months ended June 30, 2015.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 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.

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 is to be borne by opt-out customers through an initial fee and ongoing monthly charge. On June 20, 2014, the PUCT approved a settlement permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of July 24, 2015, 96 customers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On October 25, 2013, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.6 million, including a performance bonus for 2012 of $0.7 million, beginning March 1, 2014. On September 11, 2014, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.7 million beginning March 1, 2015, including a performance bonus for 2013 of $1.5 million. On May 29, 2015, TNMP filed its 2016 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.9 million, including a performance bonus of $0.6 million, to be collected beginning March 1, 2016. A hearing on the application is scheduled for August 28, 2015. TNMP records incentive bonuses upon approval by 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. The following sets forth TNMP’s most recent interim transmission cost rate increases:

Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 17, 2013	$	18.1	$	2.8
March 13, 2014	18.2		2.9
September 8, 2014	25.2		4.2
March 16, 2015	27.1		4.4

On July 17, 2015, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $7.0 million, which would increase revenues by $1.4 million annually. The application is pending before the PUCT.