PNMXO 10-Q Quarterly Report Sept. 30, 2015

PUBLIC SERVICE CO OF NEW MEXICO

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10-Q 1 pnm930201510-q.htm 9.30.2015 FORM 10-Q 10-Q

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 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

Table of Contents

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

PNM

TNMP

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

As of October 23, 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 October 23, 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 October 23, 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.

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

INDEX



	Page 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	79
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	110
ITEM 4. CONTROLS AND PROCEDURES	113
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	113
ITEM 1A. RISK FACTORS	114
ITEM 6. EXHIBITS	114
SIGNATURE	116

Table of Contents

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
CO ₂		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

Table of Contents



ISFSI		Independent Spent Fuel Storage Installation
KW		Kilowatt
KWh		Kilowatt Hour
LIBOR		London Interbank Offered Rate
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.
NEE		New Energy Economy
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
NMSC		New Mexico Supreme Court
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

Table of Contents



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
PPA		Power Purchase Agreement
PSA		Power Sales 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
SO ₂		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

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands, except per share amounts)
Electric Operating Revenues	$	417,433		$	413,951		$	1,103,187		$	1,089,008
Operating Expenses:
Cost of energy	124,255			132,499			353,939			354,532
Administrative and general	46,375			42,190			130,161			131,283
Energy production costs	42,168			43,287			129,627			136,422
Regulatory disallowances	—			—			1,744			—
Depreciation and amortization	47,503			44,295			139,013			128,424
Transmission and distribution costs	16,768			16,884			50,123			49,857
Taxes other than income taxes	18,859			17,997			55,093			51,641
Total operating expenses	295,928			297,152			859,700			852,159
Operating income	121,505			116,799			243,487			236,849
Other Income and Deductions:
Interest income	1,151			2,084			4,842			6,241
Gains on available-for-sale securities	2,536			962			12,116			8,234
Other income	6,165			2,895			16,844			7,648
Other (deductions)	(3,222		)	(2,084		)	(10,591		)	(7,185		)
Net other income and deductions	6,630			3,857			23,211			14,938
Interest Charges	27,528			30,115			86,714			89,621
Earnings before Income Taxes	100,607			90,541			179,984			162,166
Income Taxes	35,752			31,055			61,621			53,368
Net Earnings	64,855			59,486			118,363			108,798
(Earnings) Attributable to Valencia Non-controlling Interest	(3,678		)	(3,701		)	(10,909		)	(11,140		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Net Earnings Attributable to PNMR	$	61,045		$	55,653		$	107,058		$	97,262
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.77		$	0.70		$	1.34		$	1.22
Diluted	$	0.76		$	0.69		$	1.34		$	1.21
Dividends Declared per Common Share	$	0.200		$	0.185		$	0.600		$	0.555

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

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Net Earnings	$	64,855		$	59,486		$	118,363		$	108,798
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 $1,200, $(137), $(1,213) and $(3,946)	(1,862		)	210			1,882			6,256
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $3,925, $1,059, $8,838 and $4,547	(6,090		)	(1,628		)	(13,714		)	(6,997		)
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), $(1,749) and $(1,524)	905			780			2,715			2,340
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $276, $0, $276 and $53	(428		)	—			(428		)	(100		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $0, $3, $0 and $(58)	—			(6		)	—			109
Total Other Comprehensive Income (Loss)	(7,475		)	(644		)	(9,545		)	1,608
Comprehensive Income	57,380			58,842			108,818			110,406
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,678		)	(3,701		)	(10,909		)	(11,140		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Comprehensive Income Attributable to PNMR	$	53,570		$	55,009		$	97,513		$	98,870

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

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	118,363		$	108,798
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	165,563			157,687
Deferred income tax expense	62,511			55,553
Net unrealized (gains) losses on commodity derivatives	1,251			(67		)
Realized (gains) on available-for-sale securities	(12,116		)	(8,234		)
Stock based compensation expense	3,748			4,680
Regulatory disallowances	1,744			—
Other, net	(4,301		)	(642		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(23,783		)	(22,158		)
Materials, supplies, and fuel stock	(3,629		)	5,494
Other current assets	37,756			(19,816		)
Other assets	12,350			30,502
Accounts payable	1,275			79
Accrued interest and taxes	28,233			32,488
Other current liabilities	(12,731		)	(21,197		)
Other liabilities	(40,662		)	3,074
Net cash flows from operating activities	335,572			326,241

Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(411,606		)	(293,361		)
Proceeds from sales of available-for-sale securities	166,097			82,222
Purchases of available-for-sale securities	(166,268		)	(81,644		)
Return of principal on PVNGS lessor notes	21,694			20,758
Purchase of Rio Bravo	—			(36,235		)
Other, net	2,891			(3,433		)
Net cash flows from investing activities	(387,192		)	(311,693		)

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

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(3,000		)	(49,200		)
Long-term borrowings	463,605			255,000
Repayment of long-term debt	(333,066		)	(125,000		)
Proceeds from stock option exercise	7,394			5,495
Awards of common stock	(18,955		)	(15,573		)
Dividends paid	(48,188		)	(44,600		)
Valencia’s transactions with its owner	(12,107		)	(12,749		)
Other, net	(5,402		)	(2,030		)
Net cash flows from financing activities	50,281			11,343

Change in Cash and Cash Equivalents	(1,339		)	25,891
Cash and Cash Equivalents at Beginning of Period	28,274			2,533
Cash and Cash Equivalents at End of Period	$	26,935		$	28,424

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	63,046		$	60,075
Income taxes paid (refunded), net	$	(1,636	)	$	(2,529	)

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(8,748	)	$	(6,674	)

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

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015		December 31, 2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	26,935	$	28,274
Accounts receivable, net of allowance for uncollectible accounts of $1,363 and $1,466	110,562		87,038
Unbilled revenues	61,739		63,719
Other receivables	22,234		39,857
Materials, supplies, and fuel stock	67,256		63,628
Regulatory assets	4,957		47,855
Commodity derivative instruments	6,144		11,232
Income taxes receivable	5,614		6,360
Current portion of accumulated deferred income taxes	26,383		26,383
Other current assets	76,161		58,471
Total current assets	407,985		432,817
Other Property and Investments:
Investment in PVNGS lessor notes	—		9,538
Available-for-sale securities	242,795		250,145
Other investments	490		1,762
Non-utility property	3,404		3,406
Total other property and investments	246,689		264,851
Utility Plant:
Plant in service and plant held for future use	6,147,782		5,941,581
Less accumulated depreciation and amortization	2,043,482		1,939,760
	4,104,300		4,001,821
Construction work in progress	366,980		190,389
Nuclear fuel, net of accumulated amortization of $51,719 and $44,507	79,954		77,796
Net utility plant	4,551,234		4,270,006
Deferred Charges and Other Assets:
Regulatory assets	464,766		491,007
Goodwill	278,297		278,297
Commodity derivative instruments	3,369		—
Other deferred charges	100,512		92,347
Total deferred charges and other assets	846,944		861,651
	$	6,052,852	$	5,829,325

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

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015			December 31, 2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	102,600		$	105,600
Current installments of long-term debt	125,000			333,066
Accounts payable	120,052			110,029
Customer deposits	12,502			12,555
Accrued interest and taxes	81,932			53,863
Regulatory liabilities	2,205			1,703
Commodity derivative instruments	984			1,209
Dividends declared	16,063			16,063
Other current liabilities	57,249			70,194
Total current liabilities	518,587			704,282
Long-term Debt	1,980,381			1,642,024
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	949,642			891,111
Regulatory liabilities	472,035			466,143
Asset retirement obligations	111,595			104,170
Accrued pension liability and postretirement benefit cost	66,346			110,738
Commodity derivative instruments	—			477
Other deferred credits	107,072			103,759
Total deferred credits and other liabilities	1,706,690			1,676,398
Total liabilities	4,205,658			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)	1,165,895			1,173,845
Accumulated other comprehensive income (loss), net of income taxes	(71,300		)	(61,755		)
Retained earnings	668,722			609,456
Total PNMR common stockholders’ equity	1,763,317			1,721,546
Non-controlling interest in Valencia	72,348			73,546
Total equity	1,835,665			1,795,092
	$	6,052,852		$	5,829,325

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

Table of Contents

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			Non- controlling Interest in Valencia			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	7,394			—			—			7,394			—			7,394
Awards of common stock	(18,955		)	—			—			(18,955		)	—			(18,955		)
Excess tax (shortfall) from stock-based payment arrangements	(137		)	—			—			(137		)	—			(137		)
Stock based compensation expense	3,748			—			—			3,748			—			3,748
Valencia’s transactions with its owner	—			—			—			—			(12,107		)	(12,107		)
Net earnings before subsidiary preferred stock dividends	—			—			107,454			107,454			10,909			118,363
Subsidiary preferred stock dividends	—			—			(396		)	(396		)	—			(396		)
Total other comprehensive income (loss)	—			(9,545		)	—			(9,545		)	—			(9,545		)
Dividends declared on common stock	—			—			(47,792		)	(47,792		)	—			(47,792		)
Balance at September 30, 2015	$	1,165,895		$	(71,300	)	$	668,722		$	1,763,317		$	72,348		$	1,835,665

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

Table of Contents

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Electric Operating Revenues	$	333,437		$	334,993		$	870,826		$	873,434
Operating Expenses:
Cost of energy	105,708			115,097			299,302			304,365
Administrative and general	41,927			37,519			118,450			116,731
Energy production costs	42,168			43,287			129,627			136,422
Regulatory disallowances	—			—			1,744			—
Depreciation and amortization	29,042			27,524			86,446			81,629
Transmission and distribution costs	10,478			10,693			31,519			32,202
Taxes other than income taxes	10,404			10,258			31,194			30,359
Total operating expenses	239,727			244,378			698,282			701,708
Operating income	93,710			90,615			172,544			171,726
Other Income and Deductions:
Interest income	1,152			2,102			4,869			6,295
Gains on available-for-sale securities	2,536			962			12,116			8,234
Other income	5,369			1,804			13,661			5,359
Other (deductions)	(2,616		)	(1,197		)	(7,230		)	(4,844		)
Net other income and deductions	6,441			3,671			23,416			15,044
Interest Charges	19,837			20,092			59,477			59,927
Earnings before Income Taxes	80,314			74,194			136,483			126,843
Income Taxes	27,258			25,142			44,560			42,331
Net Earnings	53,056			49,052			91,923			84,512
(Earnings) Attributable to Valencia Non-controlling Interest	(3,678		)	(3,701		)	(10,909		)	(11,140		)
Net Earnings Attributable to PNM	49,378			45,351			81,014			73,372
Preferred Stock Dividends Requirements	(132		)	(132		)	(396		)	(396		)
Net Earnings Available for PNM Common Stock	$	49,246		$	45,219		$	80,618		$	72,976

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

Table of Contents

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Net Earnings	$	53,056		$	49,052		$	91,923		$	84,512
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 $1,200, $(137), $(1,213) and $(3,946)	(1,862		)	210			1,882			6,256
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $3,925, $1,059, $8,838 and $4,547	(6,090		)	(1,628		)	(13,714		)	(6,997		)
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), $(1,749) and $(1,524)	905			780			2,715			2,340
Total Other Comprehensive Income (Loss)	(7,047		)	(638		)	(9,117		)	1,599
Comprehensive Income	46,009			48,414			82,806			86,111
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,678		)	(3,701		)	(10,909		)	(11,140		)
Comprehensive Income Attributable to PNM	$	42,331		$	44,713		$	71,897		$	74,971

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

Table of Contents

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	91,923		$	84,512
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	111,371			108,069
Deferred income tax expense	46,268			45,313
Net unrealized (gains) losses on commodity derivatives	1,251			(67		)
Realized (gains) on available-for-sale securities	(12,116		)	(8,234		)
Regulatory disallowances	1,744			—
Other, net	(5,288		)	(355		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(16,220		)	(16,782		)
Materials, supplies, and fuel stock	(3,328		)	5,697
Other current assets	36,707			(20,806		)
Other assets	12,126			29,796
Accounts payable	(794		)	10,100
Accrued interest and taxes	22,856			19,984
Other current liabilities	(12,099		)	(21,586		)
Other liabilities	(34,224		)	2,841
Net cash flows from operating activities	240,177			238,482

Cash Flows From Investing Activities:
Utility plant additions	(301,410		)	(199,771		)
Proceeds from sales of available-for-sale securities	166,097			82,222
Purchases of available-for-sale securities	(166,268		)	(81,644		)
Return of principal on PVNGS lessor notes	21,694			20,758
Purchase of Rio Bravo	—			(36,235		)
Other, net	3,051			(3,404		)
Net cash flows from investing activities	(276,836		)	(218,074		)

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

Table of Contents

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	—			(49,200		)
Short-term borrowings (repayments), affiliate, net	—			(26,000		)
Long-term borrowings	313,605			175,000
Repayment of long-term debt	(214,300		)	(75,000		)
Valencia’s transactions with its owner	(12,107		)	(12,749		)
Dividends paid	(46,548		)	(30,659		)
Other, net	(4,934		)	(1,196		)
Net cash flows from financing activities	35,716			(19,804		)

Change in Cash and Cash Equivalents	(943		)	604
Cash and Cash Equivalents at Beginning of Period	25,480			21
Cash and Cash Equivalents at End of Period	$	24,537		$	625

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	42,680		$	41,606
Income taxes paid (refunded), net	$	(1,450	)	$	(215	)

Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	$	(9,933	)	$	(10,586	)

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

Table of Contents

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015		December 31, 2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	24,537	$	25,480
Accounts receivable, net of allowance for uncollectible accounts of $1,363 and $1,466	83,401		67,622
Unbilled revenues	52,342		54,140
Other receivables	19,036		37,622
Affiliate receivables	8,859		8,853
Materials, supplies, and fuel stock	64,186		60,859
Regulatory assets	3,064		43,980
Commodity derivative instruments	6,144		11,232
Income taxes receivable	6,363		6,105
Current portion of accumulated deferred income taxes	12,418		12,418
Other current assets	70,796		53,095
Total current assets	351,146		381,406
Other Property and Investments:
Investment in PVNGS lessor notes	—		9,538
Available-for-sale securities	242,795		250,145
Other investments	252		397
Non-utility property	96		96
Total other property and investments	243,143		260,176
Utility Plant:
Plant in service and plant held for future use	4,728,597		4,581,066
Less accumulated depreciation and amortization	1,556,065		1,486,406
	3,172,532		3,094,660
Construction work in progress	307,676		169,673
Nuclear fuel, net of accumulated amortization of $51,719 and $44,507	79,954		77,796
Net utility plant	3,560,162		3,342,129
Deferred Charges and Other Assets:
Regulatory assets	337,712		357,045
Goodwill	51,632		51,632
Commodity derivative instruments	3,369		—
Other deferred charges	90,389		81,264
Total deferred charges and other assets	483,102		489,941
	$	4,637,553	$	4,473,652

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

Table of Contents

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015			December 31, 2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Current installments of long-term debt	$	125,000		$	214,300
Accounts payable	95,194			86,055
Affiliate payables	17,070			18,232
Customer deposits	12,502			12,555
Accrued interest and taxes	52,994			29,298
Regulatory liabilities	2,205			1,703
Commodity derivative instruments	984			1,209
Dividends declared	132			132
Other current liabilities	40,798			52,053
Total current liabilities	346,879			415,537
Long-term Debt	1,464,991			1,276,357
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	758,182			715,814
Regulatory liabilities	435,473			425,481
Asset retirement obligations	110,545			103,182
Accrued pension liability and postretirement benefit cost	59,367			102,850
Commodity derivative instruments	—			477
Other deferred credits	90,034			86,023
Total deferred credits and liabilities	1,453,601			1,433,827
Total liabilities	3,265,471			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	(70,872		)	(61,755		)
Retained earnings	297,301			262,835
Total PNM common stockholder’s equity	1,288,205			1,262,856
Non-controlling interest in Valencia	72,348			73,546
Total equity	1,360,553			1,336,402
	$	4,637,553		$	4,473,652

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

Table of Contents

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
	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	—		—			—			—			(12,107		)	(12,107		)
Net earnings	—		—			81,014			81,014			10,909			91,923
Total other comprehensive income (loss)	—		(9,117		)	—			(9,117		)	—			(9,117		)
Dividends declared on preferred stock	—		—			(396		)	(396		)	—			(396		)
Dividends declared on common stock	—		—			(46,152		)	(46,152		)	—			(46,152		)
Balance at September 30, 2015	$	1,061,776	$	(70,872	)	$	297,301		$	1,288,205		$	72,348		$	1,360,553

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Electric Operating Revenues	$	83,996		$	78,958		$	232,361		$	215,574
Operating Expenses:
Cost of energy	18,547			17,402			54,637			50,167
Administrative and general	9,071			9,230			26,946			27,839
Depreciation and amortization	15,016			13,432			42,065			37,276
Transmission and distribution costs	6,290			6,191			18,604			17,655
Taxes other than income taxes	7,405			6,830			19,782			18,238
Total operating expenses	56,329			53,085			162,034			151,175
Operating income	27,667			25,873			70,327			64,399
Other Income and Deductions:
Other income	774			1,072			3,106			2,078
Other (deductions)	(102		)	(279		)	(349		)	(583		)
Net other income and deductions	672			793			2,757			1,495
Interest Charges	6,855			6,870			20,636			20,122
Earnings before Income Taxes	21,484			19,796			52,448			45,772
Income Taxes	7,795			7,441			19,200			17,081
Net Earnings	$	13,689		$	12,355		$	33,248		$	28,691

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
	(In thousands)
Net Earnings	$	13,689	$	12,355		$	33,248	$	28,691
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, $3, $0 and $(58)	—		(6		)	—		109
Total Other Comprehensive Income (Loss)	—		(6		)	—		9
Comprehensive Income	$	13,689	$	12,349		$	33,248	$	28,700

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	33,248		$	28,691
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	43,272			39,577
Deferred income tax expense	3,575			4,256
Other, net	(125		)	(169		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(7,563		)	(5,376		)
Materials and supplies	(301		)	(203		)
Other current assets	2,712			1,761
Other assets	(272		)	(58		)
Accounts payable	(210		)	(1,302		)
Accrued interest and taxes	19,757			19,054
Other current liabilities	1,033			(1,217		)
Other liabilities	(5,870		)	1,397
Net cash flows from operating activities	89,256			86,411
Cash Flows From Investing Activities:
Utility plant additions	(90,497		)	(88,940		)
Net cash flows from investing activities	(90,497		)	(88,940		)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	(5,000		)	—
Short-term borrowings (repayments) – affiliate, net	25,800			(10,300		)
Long-term borrowings	—			80,000
Repayment of long-term debt	—			(50,000		)
Dividends paid	(19,559		)	(16,336		)
Other, net	—			(835		)
Net cash flows from financing activities	1,241			2,529

Change in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	1		$	1

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	13,308		$	11,778
Income taxes paid (refunded), net	$	545		$	(299	)

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(216	)	$	1,658

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015		December 31, 2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable	27,161		19,416
Unbilled revenues	9,397		9,579
Other receivables	1,009		2,063
Materials and supplies	3,070		2,769
Regulatory assets	1,893		3,875
Current portion of accumulated deferred income taxes	6,398		6,398
Other current assets	1,256		938
Total current assets	50,185		45,039
Other Property and Investments:
Other investments	238		242
Non-utility property	2,240		2,240
Total other property and investments	2,478		2,482
Utility Plant:
Plant in service and plant held for future use	1,235,573		1,182,112
Less accumulated depreciation and amortization	399,479		375,407
	836,094		806,705
Construction work in progress	42,535		16,538
Net utility plant	878,629		823,243
Deferred Charges and Other Assets:
Regulatory assets	127,054		133,962
Goodwill	226,665		226,665
Other deferred charges	8,186		8,850
Total deferred charges and other assets	361,905		369,477
	$	1,293,197	$	1,240,241

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

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015		December 31, 2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	—	$	5,000
Short-term debt – affiliate	48,500		22,700
Accounts payable	14,210		14,203
Affiliate payables	2,596		2,469
Accrued interest and taxes	48,331		28,574
Other current liabilities	3,145		2,271
Total current liabilities	116,782		75,217
Long-term Debt	365,390		365,667
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	221,714		217,945
Regulatory liabilities	36,562		40,662
Asset retirement obligations	902		848
Accrued pension liability and postretirement benefit cost	6,979		7,888
Other deferred credits	6,514		7,349
Total deferred credits and other liabilities	272,671		274,692
Total liabilities	754,843		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	134,124		120,435
Total common stockholder’s equity	538,354		524,665
	$	1,293,197	$	1,240,241

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

Table of Contents

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	—		—		33,248			33,248
Dividends declared on common stock	—		—		(19,559		)	(19,559		)
Balance at September 30, 2015	$	64	$	404,166	$	134,124		$	538,354

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

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(1)	Significant Accounting Policies and Responsibility for Financial Statements

Financial Statement Preparation

In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at September 30, 2015 and December 31, 2014 , the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2015 and 2014 , and the consolidated cash flows for the nine months ended September 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 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

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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)

Consolidated Statements of Earnings. The Board declared dividends on common stock considered to be for the third quarter of $0.200 per share in September 2015 and $0.185 in September 2014, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

PNM declared and paid cash dividends on common stock to PNMR of $46.2 million and $30.3 million in the nine months ended September 30, 2015 and 2014. TNMP declared and paid cash dividends of $19.6 million and $16.3 million in the nine months ended September 30, 2015 and 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. On August 12, 2015, the FASB issued a one-year deferral in the effective date. The Company must now adopt the new standard beginning on January 1, 2018. Early adoption would be permitted beginning January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method although it is unlikely the Company would elect to early adopt the new standard. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures, but has not 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 new standard was subsequently amended to not require a reduction of debt liabilities for issuance costs related to line-of-credit arrangements. 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 September 30, 2015 , amounted to $13.9 million for PNMR, $9.7 million for PNM, and $4.0 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 significant impact on the financial statements other than the disclosure and

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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)

presentation of certain investments of the Company’s employee benefit plans that are measured using the net asset value practical expedient.


(2)	Earnings Per Share

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	61,045	$	55,653	$	107,058	$	97,262
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	100		112		103		134
Average Shares – Basic	79,754		79,766		79,757		79,788
Dilutive Effect of Common Stock Equivalents ⁽¹⁾ :
Stock options and restricted stock	362		457		377		491
Average Shares – Diluted	80,116		80,223		80,134		80,279
Net Earnings Per Share of Common Stock:
Basic	$	0.77	$	0.70	$	1.34	$	1.22
Diluted	$	0.76	$	0.69	$	1.34	$	1.21


⁽¹⁾	Excludes the effect of out-of-the-money options for 244,900 shares of common stock at September 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.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

PNMR SEGMENT INFORMATION



	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2015
Electric operating revenues	$	333,437		$	83,996		$	—		$	417,433
Cost of energy	105,708			18,547			—			124,255
Margin	227,729			65,449			—			293,178
Other operating expenses	104,977			22,766			(3,573		)	124,170
Depreciation and amortization	29,042			15,016			3,445			47,503
Operating income	93,710			27,667			128			121,505
Interest income	1,152			—			(1		)	1,151
Other income (deductions)	5,289			672			(482		)	5,479
Net interest charges	(19,837		)	(6,855		)	(836		)	(27,528		)
Segment earnings (loss) before income taxes	80,314			21,484			(1,191		)	100,607
Income taxes	27,258			7,795			699			35,752
Segment earnings (loss)	53,056			13,689			(1,890		)	64,855
Valencia non-controlling interest	(3,678		)	—			—			(3,678		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	49,246		$	13,689		$	(1,890	)	$	61,045

Nine Months Ended September 30, 2015
Electric operating revenues	$	870,826		$	232,361		$	—		$	1,103,187
Cost of energy	299,302			54,637			—			353,939
Margin	571,524			177,724			—			749,248
Other operating expenses	312,534			65,332			(11,118		)	366,748
Depreciation and amortization	86,446			42,065			10,502			139,013
Operating income	172,544			70,327			616			243,487
Interest income	4,869			—			(27		)	4,842
Other income (deductions)	18,547			2,757			(2,935		)	18,369
Net interest charges	(59,477		)	(20,636		)	(6,601		)	(86,714		)
Segment earnings (loss) before income taxes	136,483			52,448			(8,947		)	179,984
Income taxes (benefit)	44,560			19,200			(2,139		)	61,621
Segment earnings (loss)	91,923			33,248			(6,808		)	118,363
Valencia non-controlling interest	(10,909		)	—			—			(10,909		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	80,618		$	33,248		$	(6,808	)	$	107,058

At September 30, 2015:
Total Assets	$	4,637,553		$	1,293,197		$	122,102		$	6,052,852
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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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)



	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2014
Electric operating revenues	$	334,993		$	78,958		$	—		$	413,951
Cost of energy	115,097			17,402			—			132,499
Margin	219,896			61,556			—			281,452
Other operating expenses	101,757			22,251			(3,650		)	120,358
Depreciation and amortization	27,524			13,432			3,339			44,295
Operating income	90,615			25,873			311			116,799
Interest income	2,102			—			(18		)	2,084
Other income (deductions)	1,569			793			(589		)	1,773
Net interest charges	(20,092		)	(6,870		)	(3,153		)	(30,115		)
Segment earnings (loss) before income taxes	74,194			19,796			(3,449		)	90,541
Income taxes (benefit)	25,142			7,441			(1,528		)	31,055
Segment earnings (loss)	49,052			12,355			(1,921		)	59,486
Valencia non-controlling interest	(3,701		)	—			—			(3,701		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	45,219		$	12,355		$	(1,921	)	$	55,653

Nine Months Ended September 30, 2014
Electric operating revenues	$	873,434		$	215,574		$	—		$	1,089,008
Cost of energy	304,365			50,167			—			354,532
Margin	569,069			165,407			—			734,476
Other operating expenses	315,714			63,732			(10,243		)	369,203
Depreciation and amortization	81,629			37,276			9,519			128,424
Operating income	171,726			64,399			724			236,849
Interest income	6,295			—			(54		)	6,241
Other income (deductions)	8,749			1,495			(1,547		)	8,697
Net interest charges	(59,927		)	(20,122		)	(9,572		)	(89,621		)
Segment earnings (loss) before income taxes	126,843			45,772			(10,449		)	162,166
Income taxes (benefit)	42,331			17,081			(6,044		)	53,368
Segment earnings (loss)	84,512			28,691			(4,405		)	108,798
Valencia non-controlling interest	(11,140		)	—			—			(11,140		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	72,976		$	28,691		$	(4,405	)	$	97,262

At September 30, 2014:
Total Assets	$	4,358,474		$	1,216,545		$	134,190		$	5,709,209
Goodwill	$	51,632		$	226,665		$	—		$	278,297


(4)	Accumulated Other Comprehensive Income (Loss)

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

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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)



	Accumulated Other Comprehensive Income (Loss)
	PNM									TNMP		PNMR
	Unrealized									Fair Value		Fair Value
	Gain on									Adjustment		Adjustment
	Available-for-			Pension						for Cash		for Cash
	Sale			Liability						Flow		Flow
	Securities			Adjustment			Total			Hedges		Hedges			Total
	(In thousands)
Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—	$	—		$	(61,755	)
Amounts reclassified from AOCI (pre-tax)	(22,552		)	4,464			(18,088		)	—		—			(18,088		)
Income tax impact of amounts reclassified	8,838			(1,749		)	7,089			—		—			7,089
Other OCI changes (pre-tax)	3,095			—			3,095			—		(704		)	2,391
Income tax impact of other OCI changes	(1,213		)	—			(1,213		)	—		276			(937		)
Net change after income taxes	(11,832		)	2,715			(9,117		)	—		(428		)	(9,545		)
Balance at September 30, 2015	$	16,176		$	(87,048	)	$	(70,872	)	$	—	$	(428	)	$	(71,300	)



Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(57,877	)	$	(263	)	$	—	$	(58,140	)
Amounts reclassified from AOCI (pre-tax)	(11,544		)	3,864			(7,680		)	167			—		(7,513		)
Income tax impact of amounts reclassified	4,547			(1,524		)	3,023			(58		)	—		2,965
Other OCI changes (pre-tax)	10,202			—			10,202			(153		)	—		10,049
Income tax impact of other OCI changes	(3,946		)	—			(3,946		)	53			—		(3,893		)
Net change after income taxes	(741		)	2,340			1,599			9			—		1,608
Balance at September 30, 2014	$	25,007		$	(81,285	)	$	(56,278	)	$	(254	)	$	—	$	(56,532	)

Pre-tax amounts reclassified from AOCI related to “Unrealized Gain on Available-for-Sale Securities” are included in “Gains on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “Pension Liability Adjustment” are reclassified to “Operating Expenses – Administrative and general” in the Condensed Consolidated Statements of Earnings. For the nine months ended September 30, 2015 and 2014 , 22.4% and 23.6% of the pension amounts reclassified were capitalized into construction work in process and 2.5% and 1.7% 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.


(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.

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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)

Valencia

PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and nine months ended September 30, 2015 , PNM paid $4.9 million and $14.5 million for fixed charges and $0.3 million and $0.9 million for variable charges. For the three and nine months ended September 30, 2014 , PNM paid $4.8 million and $14.4 million for fixed charges and $0.3 million and $1.0 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM has concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates the entity in its financial statements. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

Results of Operations



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Operating revenues	$	5,182		$	5,061		$	15,337		$	15,300
Operating expenses	(1,504		)	(1,360		)	(4,428		)	(4,160		)
Earnings attributable to non-controlling interest	$	3,678		$	3,701		$	10,909		$	11,140

Financial Position



	September 30,		December 31,
	2015		2014
	(In thousands)
Current assets	$	3,410	$	2,513
Net property, plant, and equipment	70,471		72,321
Total assets	73,881		74,834
Current liabilities	1,533		1,288
Owners’ equity – non-controlling interest	$	72,348	$	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

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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)

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 available options. PNM cannot predict if 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 two years beyond the termination of the original lease terms. The option periods on certain leases could be further extended for up to an additional six years 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 September 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 $140.1 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 September 30, 2015 , PNM could have been required to pay the beneficial owners up to $205.8 million on January 15, 2016 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 $8.4 million at September 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.

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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)

PNM made fixed and variable payments to Delta under the PPA. For the periods from July 1, 2014 through July 17, 2014 and January 1, 2014 through July 17, 2014, PNM incurred fixed capacity charges of $0.3 million and $3.5 million and variable energy charges of $0.1 million and $0.6 million . PNM recovered the variable energy charges through its FPPAC.

PNM began including the assets, liabilities, and operations of 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 leased an interest in the EIP transmission line through April 1, 2015. 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. On September 18, 2015, PNM entered into a definitive agreement to implement the purchase by PNM of the generating capacity under this lease on January 15, 2016, at which time the purchase price will be paid by PNM and the transfer of the leased interests will take place. 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. 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 of the assets underlying the lease at that date.


(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

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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)

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 nine months ended September 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
	September 30, 2015			December 31, 2014
PNMR and PNM	(In thousands)
Current assets	$	6,144		$	11,232
Deferred charges	3,369			—
	9,513			11,232

Current liabilities	(984		)	(1,209		)
Long-term liabilities	—			(477		)
	(984		)	(1,686		)
Net	$	8,529		$	9,546

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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)

Included in the above table are $2.2 million of current assets and $3.4 million in deferred charges at September 30, 2015 and $3.0 million of current assets at December 31, 2014 related to contracts for the sale of energy from PVNGS Unit 3 through 2017 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at September 30, 2015 and December 31, 2014.

At September 30, 2015 and December 31, 2014 , PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at September 30, 2015 and December 31, 2014 , amounts posted as cash collateral under margin arrangements were $1.2 million and $3.8 million for both PNMR and PNM. At September 30, 2015 and December 31, 2014, obligations to return cash collateral were $0.1 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 $0.3 million of current assets and less than $0.1 million of current liabilities at September 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						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
PNMR and PNM	(In thousands)
Electric operating revenues	$	6,823		$	2,352		$	7,354		$	(2,124	)
Cost of energy	(78		)	(60		)	(227		)	186
Total gain (loss)	$	6,745		$	2,292		$	7,127		$	(1,938	)

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
September 30, 2015	1,227,498	(2,942,281	)
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

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

the existing contracts and does not reflect letters of credit under PNM’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
September 30, 2015	$	967	$	—	$	207
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. As of September 30, 2015 , PNM had contracted to sell 100% of PVNGS Unit 3 output through 2017, 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 the sales through 2015. There are currently no hedging arrangements in place for the 2016 and 2017 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 September 30, 2015 and December 31, 2014 , the fair value of available-for-sale securities included $237.3 million and $244.6 million for the NDT and $5.5 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.



	September 30, 2015				December 31, 2014
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	28,813	$	—	$	8,276
Equity securities:
Domestic value	11,880		42,769		17,418		45,340
Domestic growth	10,124		58,424		21,354		74,053
International and other	1		1,681		156		16,599
Fixed income securities:
U.S. Government	598		25,544		903		22,563
Municipals	3,499		61,106		5,851		68,973
Corporate and other	618		24,458		666		14,341
	$	26,720	$	242,795	$	46,348	$	250,145

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The 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 $(2.4) million and $(3.2) million for the three and nine months ended September 30, 2015 and $(1.2) million and $(0.7) million for the three and nine months ended September 30, 2014.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In thousands)
Proceeds from sales	$	71,576		$	29,103		$	166,097		$	82,222
Gross realized gains	$	8,998		$	3,134		$	22,463		$	11,616
Gross realized (losses)	$	(4,014	)	$	(936	)	$	(7,133	)	$	(2,731	)

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 September 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	$	4,558	$	8,947	$	8,947
After 1 year through 5 years	21,516		652		—
After 5 years through 10 years	23,048		—		—
After 10 years through 15 years	11,105		—		—
After 15 years through 20 years	10,593		—		—
After 20 years	40,288		—		—
	$	111,108	$	9,599	$	8,947

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 nine months ended September 30, 2015 and the year ended December 31, 2014 .

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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)

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.

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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)

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at September 30, 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)
September 30, 2015	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	28,813		$	28,813	$	—
Equity securities:
Domestic value	42,769			42,769		—
Domestic growth	58,424			58,424		—
International and other	1,681			1,681		—
Fixed income securities:
U.S. Government	25,544			24,254		1,290
Municipals	61,106			—		61,106
Corporate and other	24,458			4,169		20,289
	$	242,795		$	160,110	$	82,685

Commodity derivative assets	$	9,513		$	—	$	9,513
Commodity derivative liabilities	(984		)	—		(984		)
Net	$	8,529		$	—	$	8,529

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

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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



					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
September 30, 2015	(In thousands)
PNMR
Long-term debt	$	2,105,381	$	2,297,887	$	—	$	2,297,887	$	—
Investment in PVNGS lessor notes	$	8,824	$	8,947	$	—	$	—	$	8,947
Other investments	$	490	$	1,142	$	490	$	—	$	652
PNM
Long-term debt	$	1,589,991	$	1,719,947	$	—	$	1,719,947	$	—
Investment in PVNGS lessor notes	$	8,824	$	8,947	$	—	$	—	$	8,947
Other investments	$	252	$	252	$	252	$	—	$	—
TNMP
Long-term debt	$	365,390	$	427,940	$	—	$	427,940	$	—
Other investments	$	238	$	238	$	238	$	—	$	—

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

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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)

adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At September 30, 2015 and December 31, 2014 , PNMR had unrecognized expense related to stock awards of $6.8 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:



	Nine Months Ended September 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 nine months ended September 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	(349,468	)	$	18.61	(215,945	)	$	19.98
Forfeited	(4,061	)	$	24.81	(1,000	)	$	30.50
Expired	—		$	—	(66,201	)	$	27.90
Outstanding at September 30, 2015	245,261		$	24.81	637,359		$	19.54

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

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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)

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, which would be 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, which would be 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 September 30, 2015 , the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.0 million with a weighted-average remaining contract life of 2.38 years. At September 30, 2015 , the exercise price of 244,900 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

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



	Nine Months Ended September 30,
Restricted Stock	2015		2014
Weighted-average grant date fair value	$	20.34	$	21.27
Total fair value of restricted shares that vested (in thousands)	$	6,503	$	4,929

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)	$	1,814	$	2,199


(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.

Financing Activities

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 was repaid on August 12, 2015.

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 September 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 0.78% at September 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 1.21% at September 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. These 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.

On August 11, 2015, PNM issued $250.0 million aggregate principal amount of its 3.850% Senior Unsecured Notes due 2025. The notes will mature on August 1, 2025. Portions of the proceeds from the offering were used to repay the existing $175.0 million PNM 2014 Term Loan Agreement and to repay outstanding borrowings under the PNM Revolving Credit Facility, the PNM New Mexico Credit Facility, and PNM’s intercompany loan from PNMR.

In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 2.027% for borrowings under the PNMR 2015 Term Loan Agreement discussed above for the period from January 11, 2016 through March 9, 2018. This hedge is accounted for as a cash-flow hedge and had a fair value loss of $0.7 million at September 30, 2015, using Level 2 inputs under GAAP determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.

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 . In October 2015, the maturity date for both of these facilities was extended and they now mature on October 31, 2020. 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 September 30, 2015 , TNMP had $48.5 million in borrowings from PNMR under an intercompany loan agreement. At September 30, 2015 , the weighted average interest rate was 1.69% for the PNMR Revolving Credit Facility and 1.05% for borrowings outstanding

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

under the twelve-month PNMR Term Loan Agreement, which matures in December 2015. Short-term debt outstanding consisted of:



	September 30,		December 31,
Short-term Debt	2015		2014
	(In thousands)
PNM:
Revolving credit facility	$	—	$	—
PNM New Mexico Credit Facility	—		—
TNMP – Revolving credit facility	—		5,000
PNMR:
Revolving credit facility	2,600		600
PNMR Term Loan Agreement	100,000		100,000
	$	102,600	$	105,600

At October 23, 2015 , PNMR, PNM, and TNMP had $293.8 million , $396.8 million , and $54.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $50.0 million of availability under the PNM New Mexico Credit Facility. Total availability at October 23, 2015 , on a consolidated basis, was $795.5 million for PNMR. As of October 23, 2015 , TNMP had $36.8 million in borrowings from PNMR under an intercompany loan agreement. At October 23, 2015 , PNMR, PNM and TNMP had consolidated invested cash of $11.0 million , $34.1 million , 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.

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(Unaudited)

PNM Plans

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



	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	51		$	45		$	—	$	—
Interest cost	7,064			7,541			1,022			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		$	1		$	14		$	271	$	257

	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	153		$	136		$	—	$	—
Interest cost	21,191			22,622			3,067			3,473			570		616
Expected return on plan assets	(29,492		)	(28,533		)	(4,208		)	(4,229		)	—		—
Amortization of net (gain) loss	11,115			9,765			1,474			1,669			243		157
Amortization of prior service cost	(724		)	(724		)	(481		)	(1,008		)	—		—
Net periodic benefit cost	$	2,090		$	3,130		$	5		$	41		$	813	$	773

PNM made contributions to its pension plan trust of zero and $30.0 million in the three and nine months ended September 30, 2015 and made no contributions in the three and nine months ended September 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 $2.4 million in the three and nine months ended September 30, 2015 and $0.8 million and $2.4 million in the three and nine months ended September 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 $1.2 million in the three and nine months ended September 30, 2015 and $0.4 million and $1.2 million in the three and nine months ended September 30, 2014 and are expected to total $1.5 million during 2015 .

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

TNMP Plans

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



	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	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

	Nine Months Ended September 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	$	—		$	—		$	185		$	178		$	—	$	—
Interest cost	2,282			2,395			456			464			27		29
Expected return on plan assets	(3,315		)	(3,395		)	(390		)	(400		)	—		—
Amortization of net (gain) loss	586			499			—			(92		)	3		—
Amortization of prior service cost	—			—			—			24			—		—
Net Periodic Benefit Cost (Income)	$	(447	)	$	(501	)	$	251		$	174		$	30	$	29

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 nine months ended September 30, 2015 and zero and $0.3 million in the three and nine months ended September 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 nine months ended September 30, 2015 and 2014 and are expected to total $0.1 million during 2015 .


(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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement. 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. APS anticipates submitting a $12.3 million claim in the fourth quarter of 2015 for costs paid between July 1, 2014 and June 30, 2015. In the three months ended June 30, 2015, PNM recorded claims of $1.3 million , including $0.5 million credited back to PNM’s customers, for costs paid between July 1, 2014 and June 30, 2015. Thereafter, PNM began recording estimated claims quarterly.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At September 30, 2015 and December 31, 2014, PNM had a liability for interim storage costs of $12.0 million and $12.3 million included in other deferred credits.

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(Unaudited)

On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision 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.

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.

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(Unaudited)

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. Although the parties filed periodic status reports with the Tenth Circuit, the proceedings were being held in abeyance as agreed to by the parties. In August 2015, the Tenth Circuit dismissed this matter on mootness grounds.

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 encompassed 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

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(Unaudited)

contract. PNM anticipates installation of SNCRs and BDT equipment will 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 for additional information regarding the 40 MW of solar PV facilities and a CCN for the gas facility. 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 subsequently withdrew from 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 (reflecting the $26 million transfer to SJGS Unit 4) undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a 20 year period and would include a return on the unrecovered amount at PNM’s WACC

•

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

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(Unaudited)


•	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 this stipulation had been approved as filed, PNM estimated it would have incurred 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. The regulatory disallowance would have been recorded upon approval by the NMPRC and satisfaction of any material conditions precedent. Based on the provisions of the stipulation as filed and PNM’s projection of December 31, 2017 book values, PNM estimated the net pre-tax regulatory disallowance would have been 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 (without any amounts being transferred between units), 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 were to issue an order adopting all of the modifications to the stipulation recommended by the Hearing Examiner, PNM estimated the net pre-tax regulatory disallowance referenced above would be between $145 million and $155 million . Except as noted below, the NMPRC has not acted on the stipulation or certification.

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. On August 13, 2015, as a result of the facilitation process, PNM, the staff of the NMPRC, the NMAG, Western Resource Advocates, and the Coalition for Clean Affordable Energy filed a settlement agreement (the “Supplemental Stipulation”) with the NMPRC. NMIEC, Interwest Energy Alliance, and New

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(Unaudited)

Mexico Independent Power Producers subsequently joined in the Supplemental Stipulation. NEE opposes the Supplemental Stipulation. The stipulating parties agreed that the October 2014 stipulation described above should be approved, as modified by the Supplemental Stipulation (collectively, the “Stipulated Settlement”). Under the terms of the Stipulated Settlement:


•	PNM would retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) at December 31, 2017 and recover, over 20 years, 50% (estimated to be approximately $128.5 million ) of their undepreciated net book value at that date and earn a regulated return on those costs


•	PNM would be granted an unconditional CCN for 132 MW in SJGS Unit 4, with an initial book value of zero , plus the costs of SNCR and other capital additions


•	No later than December 31, 2018, and before entering into an agreement for post-2022 coal supply for SJGS, PNM would file its position and supporting testimony in an NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022; all parties agree to support this case being decided within six months


•	PNM would be authorized to acquire 65 MW of SJGS Unit 4 as excluded utility plant; PNM and PNMR commit that no further coal-fired merchant plant will be acquired at any time by PNM, PNMR, or any PNM affiliate; PNM is not precluded from seeking a CCN to include the 65 MW or other coal capacity in rate base

•

Beginning January 1, 2020, for every MWh produced by 197 MW of coal-fired generation from SJGS Unit 4, PNM will acquire and retire one MWh of RECs or allowances that include a zero-CO ₂ emission attribute compliant with EPA’s Clean Power Plan; this REC retirement is in addition to what is required to meet the RPS; the cost of these RECs are to be capped at $7.0 million per year and will be recovered in rates; PNM should purchase EPA-compliant RECs from New Mexico renewable generation unless those RECs are more costly


•	PNM will accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022; cost recovery for PNM’s BDT project on those units will be determined in PNM’s next general rate case consistent with the Certification of Stipulation


•	PNM would be granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017, including transmission assets associated with PVNGS Unit 3, (estimated to be approximately $150 million )


•	Not recover approximately $20 million of other costs incurred in connection with CAA compliance


•	PNM’s 2014 IRP docket will be closed without other NMPRC action

If the NMPRC issues an order that modifies the Stipulated Settlement, any stipulating party can void it. Given the terms of this agreement, ABCWUA withdrew its opposition to the original stipulation and its pending motion to void the Capacity Option and Funding Agreement (“COFA”) discussed below. However, NEE filed a motion to void the COFA.

Approval of the NMPRC is required in order for the Stipulated Settlement to become effective. The Hearing Examiner scheduled a hearing on PNM’s application concerning BART for SJGS to begin on October 13, 2015. The hearing on the Stipulated Settlement was held from October 13, 2015 through October 20, 2015.

NEE previously filed motions before the NMPRC requesting that four of the five NMPRC commissioners recuse themselves, alleging they had improper ex-parte communications, were biased, and had pre-judged the outcome of the BART case. Each of the four commissioners declined to recuse themselves. On October 5, 2015, NEE filed a Petition for a Writ of Mandamus and Request for Stay in the NMSC requesting the four commissioners be recused from this case and that PNM’s application be dismissed. On October 9, 2015, the NMSC issued orders that allowed the hearing conducted by the Hearing Examiner to proceed, but ordered that any action by the NMPRC be stayed, pending a decision by the NMSC on NEE’s petition.

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(Unaudited)

PNM filed its response in opposition to NEE’s petition on October 27, 2015 and oral argument before the NMSC is scheduled for November 9, 2015. PNM anticipates the NMSC will issue a timely ruling on NEE’s petition. If the court denies NEE’s petition, PNM expects the NMPRC would be able to render a decision before December 31, 2015. PNM believes that NEE’s petition does not satisfy the legal requirements for a writ of mandamus. PNM believes that if the NMSC mandates recusal, the “Rule of Necessity” should be applied and that the NMSC should direct the recused commissioners to rule on the BART case and render a decision.

If the NMPRC does not approve the shutdown of SJGS Units 2 and 3, SJGS would not be able to comply with the RSIP after December 31, 2017. PNM is unable to predict the outcome of the NMSC proceeding, what action the NMPRC will take or when it will take such action, whether any party will void the Stipulated Settlement, or the ultimate outcome of this matter.

If the Stipulated Settlement is approved by the NMPRC, PNM would record a regulatory disallowance upon satisfaction of any material conditions precedent. At September 30, 2015, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $279 million and its net book value of PVNGS Unit 3 was approximately $147 million . PNM estimates the undepreciated value in SJGS Units 2 and 3 at December 31, 2017 will be approximately $257 million , 50% of which would be recovered over a 20 year period, including a return on the unrecovered amount at PNM’s WACC. PNM currently estimates the net book value of PVNGS Unit 3 at December 31, 2017 will be approximately $150 million ( $1,118 per KW). If the NMPRC were to issue an order adopting all of the provisions of the Stipulated Settlement, PNM estimates the net pre-tax regulatory disallowance would be an amount between $145 million and $155 million although the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order and PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values.

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 stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and 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 SJGS Unit 4 prior to the shutdown of 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 percentage. 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,

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(Unaudited)

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 SJGS Unit 4, notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs in that unit unsubscribed. 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 the 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 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. As discussed under NMPRC Filing above, ABCWUA subsequently withdrew its pending motion to void the COFA, but NEE later filed a separate motion to void the COFA together with a filing opposing the Stipulated Settlement.

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 the exit date, which is anticipated to be December 31, 2017, PNM and PNMR Development would acquire 132 MW and 65 MW of the capacity in SJGS Unit 4 from the California owners, as contemplated by the COFA. As discussed under NMPRC Filing above, the Stipulated Settlement would allow PNM to acquire the 65 MW, which the RA anticipates will be acquired by PNMR Development. PNMR currently anticipates that, if all necessary approvals are received and the RA becomes effective, PNMR Development would transfer the rights and obligations related to the 65 MW to PNM prior to December 31, 2017 in order to facilitate dispatch of power from that capacity.

The RA is dependent on and would become effective upon the last of the approval of the underlying transactions by NMPRC and FERC and the effective date of a new coal supply agreement (“CSA”) for SJGS. The effectiveness of the new CSA is dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, as discussed in Coal Supply below. The agreement for the purchase of the mine operation will terminate if its closing has not occurred by June 30, 2016. It is currently anticipated that the new CSA 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

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(Unaudited)

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 May 1, 2015 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 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 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 the fully executed RA and related agreements along with supporting testimony on July 31, 2015.

On September 25, 2015, PNM made an application at FERC seeking certain approvals necessary for implementation of the restructured SJGS participation agreements and is planning on supplementing its application in November 2015. FERC has established November 24, 2015 as the deadline for responses to PNM’s application. PNM requested that FERC rule on its application by December 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. If timely regulatory approvals required for the RA and new CSA to become effective on January 1, 2016 are not obtained, payments from the exiting participants would be delayed. In addition, PNM and its customers would not receive the full benefits of the new coal arrangements under the RA and new CSA. A significant delay could impact the viability of the RA and could require renegotiation of the restructuring, which could result in terms and conditions that are substantially different than the arrangements under the RA.

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 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. PNM subsequently submitted several requests that the owners of Unit 4 approve certain expenditures critical to comply with the time frame in the RSIP, as well as requests to approve the total forecasted project expenses. The required majority of 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, PNM, as operating agent for SJGS, issued several “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 SJGS 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

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(Unaudited)

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 Four Corners FIP with a 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 July 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 required the approval of the DOI, as did a related federal rights-of-way grant that culminated in the issuance of a DOI Record of Decision on July 17, 2015. The Record of Decision 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 occurred in late July 2015. 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 $91.4 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.

Carbon Dioxide Emissions

On August 3, 2015, EPA established final standards to limit CO ₂ emissions from power plants. EPA took three separate but related actions in which it: (1) established the final carbon pollution standards for new, modified and reconstructed power plants; (2) established the final Clean Power Plan to set standards for carbon emission reductions from existing power plants; and (3) released a proposed federal plan associated with the final Clean Power Plan. The Clean Power Plan was published on October 23, 2015. Multiple states, utilities, and trade groups subsequently filed petitions for review and motions to stay in the D.C. Circuit.

The Clean Power Plan establishes state-by-state targets for carbon emissions reduction and requires states to submit initial plans to EPA by September 6, 2016. EPA may grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension must submit an update to EPA in 2017. All final state plans must be submitted to EPA by 2018. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. State measures plans may only be used with mass-

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based goals and must include “backstop” federally enforceable standards that will become effective if the state measures fail to achieve the expected level of emission reductions. Because Four Corners is located on Navajo Nation land, the Four Corners FIP, discussed above, will determine how the final Clean Power Plan regulations will affect that plant. APS continues to advocate for Clean Power Plan compliance options that provide maximum operational flexibility. APS will continue to monitor these standards as they are implemented. PNM is currently reviewing the new CO ₂ emission reductions standards, but cannot predict the impact they may have on its operations or a range of the potential costs of compliance.

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, SO ₂ , ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO ₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO ₂ and the 24-hour SO ₂ 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 SO ₂ NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO ₂ sources to identify maximum 1-hour SO ₂ concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO ₂ 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 SO ₂ 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 SO ₂ 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 SO ₂ 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 SO ₂ emissions are below the tonnages set forth in 1) above. EPA regions sent 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 SO ₂ non-attainment designations. NMED did not receive a letter.

On August 11, 2015, EPA released the Data Requirements Rule for SO ₂ , telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO ₂ NAAQS. If NMED chooses the modeling approach that EPA encourages states to adopt, the NMED must submit a modeling protocol for SJGS to EPA by July 1, 2016. NMED must then submit modeling results for SJGS to EPA by January 13, 2017. However, if NMED chooses the monitoring approach, a more relaxed schedule would apply. If SJGS can accept a federally enforceable 2,000 tons per year source-wide limit before January 13, 2017, modeling would not be required by EPA. PNM is currently evaluating the rule to understand its impacts.

PNM believes that compliance with the 1-hour SO ₂ 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 SO ₂ 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, SO ₂ , 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 to 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 proposed a secondary standard to provide protection against cumulative exposures that can damage plants and trees. To achieve this level of protection, EPA proposed an 8-hour secondary standard at a level within the range of 65 to 70 ppb. On October 1, 2015, EPA

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finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 ppb to 70 ppb. With ozone standards becoming more stringent, fossil-fueled generation units will come under increasing pressure to reduce emissions of nitrogen oxides and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas. EPA plans to propose rules and guidance over the next year to help states with potential nonattainment areas implement the revised standards. EPA also plans to update its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data are affected by events outside an area’s control.

As required by the CAA, EPA anticipates making attainment/nonattainment designations for the revised standards by late 2017. Those designations likely will be based on 2014-2016 air quality data. 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.

Should San Juan County become non-attainment for ozone, SJGS could be required to install further controls to meet the new ozone NAAQS. Until EPA approves attainment designations for the Navajo Nation and releases a proposal to implement the revised ozone NAAQS, APS is unable to predict what impact the adoption of these standards may have on Four Corners. 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.

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 from $0.7 million to $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.

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 agreed on terms of a settlement. 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 and published notice of the filing in the Federal Register. On August 17, 2015, the consent decree was entered by the court, marking resolution to the litigation. The settlement resolves 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 requires installation of pollution control technology and implementation of other measures to reduce SO ₂ 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 also requires 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 is responsible

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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.

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. A stay in this matter has expired although the parties continue to 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

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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.

On August 27, 2015, PNM submitted a request to EPA to terminate the SJGS National Pollutant Discharge Elimination System (“NPDES”) permit. Although SJGS has been a zero discharge facility for several years, EPA had required the plant to maintain a NPDES permit. On September 22, 2015, EPA issued a letter approving the termination request. The cooling water intake structure rule still applies to SJGS as the plant operates under the EPA NPDES Multi-Sector General Stormwater Permit (“MSGP”). On June 4, 2015, the EPA reissued and revised the MSGP. PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS related to cooling water intake structures.

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.

EPA signed the final Steam Electric Effluent Guidelines Rule on September 30, 2015 and released the pre-publication copy. The final rule phases in the new, more stringent requirements in the form of effluent limits for arsenic, mercury, selenium, and nitrogen for wastewater discharged from wet scrubber systems and zero discharge of pollutants in ash transport water that must be incorporated into plants’ NPDES permits. Each plant must comply between 2018 and 2023 depending on when it needs a new/revised NPDES permit.

Because SJGS is zero discharge for wastewater and no longer holds an NPDES permit, it is expected that minimum to no requirements will be imposed. Reeves Station, a PNM-owned gas-fired generating station, discharges cooling tower blowdown to a publicly owned treatment works and holds an NPDES permit. Applicability of the rule will need to be assessed. It is expected that minimum to no requirements will be imposed at Reeves.

Based upon the requirements of the final Steam Electric Effluent Guidelines Rule, 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. Until a draft NPDES permit is proposed for Four Corners, APS is uncertain what will be required to comply with the finalized effluent limitations. However, APS has indicated it believes that compliance costs at Four Corners will be immaterial. 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

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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.

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 sets minimum criteria for existing and new CCB landfills and existing and new CCB surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements.

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. Based upon the requirements of the final rule, PNM conducted a CCB assessment at SJGS and will make minor modifications at the plant to ensure that there are no facilities which would be

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considered impoundments under the rule. PNM 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. 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. No changes are required at SJGS as a result of the Supreme Court action.

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 September 30, 2015 and December 31, 2014, prepayments for coal, which are included in other current assets, amounted to $44.9 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 recognized 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.

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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, which 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, Tucson, 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. The stock purchase agreement will terminate on June 30, 2016 if its closing has not occurred. 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 of PNM’s coal costs are passed through the 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 on that date.

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

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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 and PNM’s current ownership share of SJGS, PNM’s remaining payments for mine reclamation, in future dollars, are estimated to be $55.5 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of September 30, 2015. At September 30, 2015 and December 31, 2014, liabilities, in current dollars, of $24.7 million and $25.7 million for surface mine reclamation and $9.3 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), the SJGS owners and PNMR Development negotiated the terms of an amended agreement to fund 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’s funding level would increase by $4.6 million in 2015 and $4.3 million in 2016 from the 2014 level.

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, 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 March 2016.

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

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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 filed a notice of appeal with the New Mexico Court of Appeals on August 31, 2015. 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 certain policy conditions, sublimits, 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,

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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

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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 filed requests for rehearing of these orders. On August 28, 2015, SPS filed settlement documentation with FERC, including a settlement agreement to which PNM was a party. If approved by FERC, the settlement would resolve all outstanding fuel cost adjustment and rate issues between SPS and PNM. Under the settlement, SPS would pay PNM $4.2 million , including interest through December 31, 2014. Of this amount, $2.6 million would be passed back to PNM’s customers through its FPPAC. FERC staff filed comments indicating they were not opposed to the settlement. FERC approved the settlement on October 29, 2015, at which time it was recorded by PNM.

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 allottees’ 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. On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. 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.

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PNM

New Mexico General 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. 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. 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.

On August 29, 2015, PNM filed a new application with the NMPRC for a general increase in retail electric rates. The application proposes a revenue increase, including base fuel revenues, of $123.5 million . PNM’s new application is based on a FTY period beginning October 1, 2015, which meets the NMPRC’s current interpretation of the FTY statute discussed below. The proposed ROE is 10.5% . The primary drivers of PNM’s identified revenue deficiency are infrastructure investments and the recovery of those investment dollars, including depreciation based on an updated depreciation study, and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The new application includes several proposed 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 include increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. PNM requested that the proposed new rates become effective beginning in July 2016. The NMPRC’s designated Hearing Examiner has established a procedural schedule that anticipates a public hearing on the proposed new rates will begin on March 14, 2016.

Proceeding Regarding Definition of Future Test Year

On June 25, 2015, PNM filed a Notice of Appeal to the NMSC, challenging the NMPRC’s June 3, 2015 written order. There is no required timeframe for the NMSC to act on PNM’s appeal. Two other utilities have filed separate notices of appeals with the NMSC and the ABCWUA filed a notice of cross appeal. On July 15, 2015, the NMPRC filed its Motion for Stay of Proceeding at the NMSC and for Remand of Jurisdiction, seeking the ability to conduct a rulemaking process on the definition

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and parameters of a FTY for rate cases. PNM opposed the motion. On July 31, 2015, PNM and the NMPRC filed a joint motion for a temporary 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. The NMSC has not acted on the pending motions.

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, 3% distributed generation, and 5% other.

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

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 $78.0 million , which is included in PNM’s current construction expenditure forecast. 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 New Mexico General 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 .

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 was held in September 2015 and an order from the NMPRC is expected by November 30, 2015. The Hearing Examiner issued a Recommended Decision on October 20, 2015 that recommends approval of the plan and the proposed rider adjustment with some minor modifications. These adjustments do not affect the amount of revenue that will be collected through the rider in 2016.

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

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$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 discussed above.

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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. The Stipulated Settlement regarding PNM’s application to abandon SJGS Units 2 and 3 described in Note 11 would, if approved by the NMPRC, result in the closing of the 2014 IRP docket without further NMPRC action.

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 opposed the stipulated agreement. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommended rejection of the agreement as proposed, and recommended several modifications to the agreement. On August 13, 2015, PNM and certain parties to the case filed an agreement that, if approved by the NMPRC, would modify the stipulation and settle all issues in the case. Others oppose the modified stipulation. Additional information concerning the NMPRC filing, including a summary of the terms of the modified stipulation, and related proceedings before the NMSC is set forth in Note 11. PNM anticipates an order from the NMPRC in the fourth quarter of 2015. On September 25, 2015, PNM made an application at FERC seeking certain approvals necessary for implementation 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 after the date of EPE’s 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 estimated the cost of the facility, which would be located at SJGS, 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 to the SJGS Unit 2 and 3 retirement case filed a motion to consolidate this CCN case with the retirement case, which motion was subsequently withdrawn. The NMPRC has scheduled a hearing on the requested CCN to begin on February 22, 2016. PNM intends to re-evaluate the timing and resource requirements for installation of the natural gas-fired unit requested in the CCN proceeding, including the potential for a smaller unit, along with other possible power resources, taking into consideration PNM’s recently revised lower load forecast and the impacts of the NEC settlement agreement recently filed with FERC, which is discussed below. This process could delay the hearing on the CCN, as well as its approval, and the in-service date of a replacement power resource, PNM’s current construction expenditure forecast includes a 100 MW gas-fired unit with an estimated cost of $101.8 million. 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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. 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. PNM filed for rehearing of FERC’s order regarding the ROE. 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 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 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 PSA.

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. On May 8, 2015, PNM filed an intervention and protest 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 held the hearing in abeyance to provide time for settlement judge procedures.

Following proceedings before a settlement judge, PNM and NEC entered into, and filed with FERC, a settlement agreement on October 29, 2015 that includes certain amendments to the PSA and related contracts on file with FERC that, if approved by FERC, would settle this matter. Under the settlement agreement, PNM would continue to serve all of NEC’s load through December 31, 2015 at rates that are substantially consistent with those currently provided under the PSA. In 2016, PNM would serve all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC would also pay certain third-party transmission costs that it did not pay in 2014. The PSA and related transmission agreements would terminate on December 31, 2016. In 2017, PNM would serve 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. The filing requests that, pending approval of the agreement, FERC allow interim rates, which reflect the settlement, to be charged under the PSA. PNM is unable to predict if FERC will allow the interim rate request or approve the settlement.

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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)

City of Gallup, New Mexico Contract

PNM provided both energy and power services to Gallup, previously 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 New Mexico General 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 October 23, 2015, 94 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.

On October 2, 2015, TNMP filed a reconciliation of the costs and savings of its AMS deployment program with the PUCT. Those costs include $71.0 million in capital costs and $18.0 million in operation and maintenance expenses. However, since the deployment is not complete and the total program costs to date are $1.5 million below the original approved forecasts, TNMP is not requesting a change to its monthly surcharge amount. The reconciliation is subject to prudency and reasonableness review by the PUCT. No procedural schedule or hearings have been set for this matter.

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 mandated savings goals). 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 $6.0 million , including a performance bonus of $0.7 million ,

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

to be collected beginning March 1, 2016. The parties entered a unanimous stipulation approving TNMP’s request on August 10, 2015. On September 11, 2015, the PUCT approved the request. 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
September 10, 2015	7.0		1.4


(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. The

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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)

estimate was further refined as of September 30, 2015 that resulted in an additional impairment of the New Mexico net operating loss carryforward of $0.3 million , of which $0.2 million was recorded by PNM and $0.1 million was recorded in the Corporate and Other segment. This refinement resulted in an additional impairment of the New Mexico wind energy production tax credit carryforwards of $1.0 million , which was recorded in the Corporate and Other segment. TNMP had no such impairments.


(14)	Related Party Transactions

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(In thousands)
Services billings:
PNMR to PNM	$	21,894	$	20,813	$	65,961	$	64,069
PNMR to TNMP	6,707		6,471		20,366		20,695
PNM to TNMP	136		142		424		402
TNMP to PNMR	—		20		—		21
Interest billings:
PNMR to TNMP	34		65		167		245
PNMR to PNM	10		1		38		55
PNM to PNMR	24		28		79		79
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 considers 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 considers 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. More weight is placed 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 considers 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 evaluates, 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.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In 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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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 758,000 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 regulated businesses


•	Delivering above industry-average earnings and dividend growth


•	Maintaining solid investment grade credit ratings

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


•	Maintaining strong plant performance, system reliability, and employee safety


•	Delivering a superior customer experience


•	Environmental leadership in their business operations


•	Supporting the communities in their service territories

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%. 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, primarily due to procedural defects, and reject it. PNM disagreed with the Hearing Examiner’s Initial Recommended Decision and filed exceptions. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision and dismissed PNM’s application.

On August 29, 2015, PNM filed a new application with the NMPRC for a general increase in retail electric rates. The application proposes a revenue increase of $123.5 million, including base fuel revenues. The application is based on a FTY beginning October 1, 2015, which meets the NMPRC’s interpretation of the FTY statute discussed below, and a ROE of 10.5%. The primary drivers of PNM’s identified revenue deficiency are infrastructure investments and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The new application includes several proposed 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 include increased customer and demand charges, a revenue decoupling pilot program

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applicable to residential and small power customers, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. New rates are expected to become effective in the third quarter of 2016.

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 NMSC, challenging the NMPRC’s order. There is no required timeframe for the NMSC to act on PNM’s appeal. Several other utilities have filed separate notices of appeals with the NMSC and one party to PNM’s rate case filed a notice of cross appeal. The NMPRC has requested that the NMSC 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. PNM and the NMPRC filed a joint motion for a temporary 30-day stay and remand of PNM’s appeal so that the NMPRC can reconsider its FTY order in PNM’s 2014 rate case. The NMSC has not acted on the pending motions.

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 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. PNM has allocated a portion of its generation assets to serve FERC wholesale generation services customers for a number of years. Recently, the low natural gas price environment has caused market prices for power to be substantially lower than what PNM is able to offer customers under the cost of service model that FERC requires PNM to use. As a result of this change in market conditions, PNM has not been earning an adequate return on the assets required to serve wholesale contracts and has decided to stop pursuing wholesale contracts that are served with the same generation assets that serve retail customers.

PNM had a PSA 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 the PSA. PNM intervened, requesting that FERC deny NEC’s petition. On July 16, 2015, FERC set the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA and held the hearing in abeyance to provide time for settlement judge procedures. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the PSA.

On October 29, 2015, PNM and NEC entered into, and filed with FERC, a settlement agreement that includes amendments to the PSA and related contracts, subject to FERC approval. Under the agreement, PNM would continue to serve all of NEC’s load through December 31, 2015 at rates that are substantially consistent with those currently provided under the PSA. In 2016, PNM would serve all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC would also pay certain third-party transmission costs that it did not pay in 2014. The PSA would terminate on December 31, 2016. In 2017, PNM would continue to serve 10 MW of NEC’s load under a short-term coordination tariff at a rate lower than provided under the PSA, but higher than prices currently available under short-term market rates. Although the settlement agreement will negatively impact results of operations in 2016 and 2017, PNM expects to be able to mitigate these impacts through market sales of power that would have been sold to NEC, reductions in fuel and transmission expenses, and other measures. PNM anticipates that, in future general rate cases, assets and costs previously assigned to serve NEC will be reassigned, primarily to retail customers. PNM is unable to predict if FERC will approve the settlement.

On June 29, 2014, the contract to provide power to Gallup, previously PNM’s second largest customer for wholesale generation services expired. PNM’s general rate case application discussed above includes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.

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.

Currently, PNM’s 134 MW interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates. The power generated

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from that interest is sold into the wholesale market and any earnings or losses are realized by shareholders. As part of compliance with the requirements for BART at SJGS discussed below, PNM has requested NMPRC approval to include PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018.

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 growth in ongoing EPS.

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.

Delivering Above Industry-Average Earnings and Dividend Growth

PNMR’s strategic goal to deliver above industry-average earnings and dividend growth enables investors to realize the value in the Company’s business. PNMR’s current target is seven to nine percent earnings growth through 2019. Earnings growth is based on ongoing earnings, which is a non-GAAP financial measure that 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.

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.

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. 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 advanced meters for homes and businesses across its Texas service area. Through September 30, 2015 , TNMP had completed installation of more than 210,000 advanced meters, which is approximately 87% 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 an advanced electric grid, installation of advanced meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. In addition,

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TNMP is installing a new outage management system that will leverage capabilities of the advanced metering infrastructure 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 facility is expected to go into service in late 2015.

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 energy demand 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 new federal regulations for CO ₂ 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 PPAs. 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. The application for a general rate increase discussed above includes recovery of the costs associated with the new 40 MW solar facilities. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 43 MW at September 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 advanced grid concepts. The facility was the nation’s first solar storage facility fully integrated into a utility’s power grid.

Since 2003, PNM has purchased 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 3 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 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.

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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. However, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by early 2016. A RSIP was approved by the EIB and EPA. PNM anticipates installation of SNCRs and related BDT equipment will 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 SO ₂ , particulate matter, CO ₂ , 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 proposed stipulation to settle this case. A public hearing in the NMPRC case was held in January 2015. 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. PNM filed exceptions to the certification. Except as noted below, the NMPRC has not acted on the stipulation or certification.

In June 2015, the NMPRC designated a facilitator to determine whether an uncontested settlement among some or all of the parties in this case could be accomplished. On August 13, 2015, as a result of the facilitation process, a settlement agreement was filed with the NMPRC. In addition to PNM, the staff of the NMPRC, the NMAG, Western Resource Advocates, the Coalition for Clean Affordable Energy, NMIEC, Interwest Energy Alliance, and New Mexico Independent Power Producers support the settlement agreement. NEE opposes the settlement agreement. The stipulating parties agreed that the October 2014 stipulation should be approved, as modified by the settlement agreement (collectively, the “Stipulated Settlement”). Under the terms of the Stipulated Settlement, if approved by the NMPRC, PNM would:


•	Retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) at December 31, 2017 and recover, over 20 years, 50% (estimated to be approximately $128.5 million) of their undepreciated net book value at that date and earn a regulated return on those costs


•	Be granted a CCN for 132 MW in SJGS Unit 4, with an initial book value of zero, plus SNCR costs and whatever portion of BDT costs the NMPRC determines to be reasonable and prudent to be allowed for recovery in rates


•	Be granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017 (estimated to be approximately $150 million)


•	Be authorized to acquire 65 MW of SJGS Unit 4 as merchant utility plant, which would not be included in rates charged to retail customers


•	Accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022 (cost recovery for PNM’s BDT project on those units will be determined in PNM’s next general rate case)


•	Make a NMPRC filing in 2018 to determine the extent that SJGS should continue serving PNM’s customers’ needs after mid-2022


•	Retire one MWh of RECs that include a zero-CO ₂ emission attribute compliant with EPA’s Clean Power Plan beginning January 1, 2020 for every MWh produced by 197 MW of coal-fired generation from SJGS Unit 4 (the cost of these RECs would be capped at $7.0 million per year and recovered in rates)


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

If the NMPRC issues an order that modifies the Stipulated Settlement, any stipulating party can void it. Although NEE filed a petition at the NMSC requesting four of the five NMPRC commissioners be recused from this case and to stay the proceedings, the NMSC issued orders that allowed the hearing to be conducted by the Hearing Examiner, but ordered that any final action by the NMPRC be stayed, pending a decision by the NMSC on the petition. A hearing was held from October 13, 2015 through October 20, 2015. Oral argument on the NEE’s petition is scheduled for November 9, 2015 before the NMSC. PNM is unable to predict the outcome of the NMSC proceeding, whether NMPRC and other required approvals will be obtained and other conditions satisfied in order for the agreements discussed above to become effective and restructuring consummated, whether any

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party will void the Supplemental Stipulation, or the ultimate outcome of this matter. If the NMPRC were to issue an order adopting all of the provisions of the Stipulated Settlement, PNM estimates it would incur a pre-tax regulatory disallowance between $145 million and $155 million.

In connection with the implementation of the RSIP and the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants 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 future 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 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 with the NMPRC. On July 31, 2015, PNM filed fully executed restructuring agreements.

The San Juan Project Restructuring Agreement (“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. Effectiveness of the RA is dependent on approvals by NMPRC and FERC, as well as the effectiveness of a new coal supply agreement (“CSA”) for SJGS. Effectiveness of the CSA is dependent upon the closing of the purchase of SJCC mining operation by the new third-party miner. It is currently anticipated that the CSA and the RA will become effective contemporaneously 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. 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.

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 also were 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. Accordingly, PNM has requested that the owners of Unit 4 approve 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. Therefore, PNM issued several “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 recent 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, SO ₂ , particulate matter, and mercury. Since 2006, SJGS has reduced NOx emissions by 42%, SO ₂ by 67%, particulate matter by 71%, and mercury by 95%.

Energy Efficiency

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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 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 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 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.

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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 also demonstrate TNMP's commitment to more than just delivering electricity by partnering with customers to optimize their energy usage.

Economic Factors

In the nine months ended September 30, 2015 , PNM experienced a decrease in weather normalized retail load of 1.4% compared to 2014. There continue to be signs that New Mexico’s economy is stabilizing. However, economic growth continues to be slow and the economic data provides conflicting indicators. Job growth in Albuquerque has increased, but is still below the national average. Housing prices in New Mexico increased in the first quarter of 2015 compared to the first quarter of 2014. In the nine months ended September 30, 2015 , TNMP’s weather normalized retail load increased 2.7% compared to 2014. Since the recent recession, Texas has fared better than the national average in job growth and unemployment. However, there has been some recent softening in job growth, particularly in the Houston area that appears to be related to lower oil prices. 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 September 30,							Nine Months Ended September 30,
	2015		2014		Change			2015		2014		Change
	(In millions, except per share amounts)
Net earnings attributable to PNMR	$	61.0	$	55.7	$	5.4		$	107.1	$	97.3	$	9.8
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	$	0.76	$	0.69	$	0.07		$	1.34	$	1.21	$	0.13

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



	Three Months Ended		Nine Months Ended
	September 30, 2015		September 30, 2015
	(In millions)
PNM	$	4.0	$	7.6
TNMP	1.3		4.5
Corporate and Other	—		(2.4		)
Net change	$	5.4	$	9.8

PNMR’s operational results were affected by the following:


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


•	Warmer weather in three months ended September 30, 2015, partially offset by milder weather in the first six months of 2015


•	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

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•	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 have been extended to expire in October 2020. 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 $795.5 million at October 23, 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 $2,603.8 million for 2015-2019, including amounts expended through September 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, 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 September 30,									Nine Months Ended September 30,
	2015			2014			Change			2015			2014			Change
	(In millions)
Electric operating revenues	$	333.4		$	335.0		$	(1.6	)	$	870.8		$	873.4		$	(2.6	)
Cost of energy	105.7			115.1			(9.4		)	299.3			304.4			(5.1		)
Margin	227.7			219.9			7.8			571.5			569.1			2.4
Operating expenses	105.0			101.8			3.2			312.5			315.7			(3.2		)
Depreciation and amortization	29.0			27.5			1.5			86.4			81.6			4.8
Operating income	93.7			90.6			3.1			172.5			171.7			0.8
Other income (deductions)	6.4			3.7			2.7			23.4			15.0			8.4
Net interest charges	(19.8		)	(20.1		)	0.3			(59.5		)	(59.9		)	0.4
Segment earnings before income taxes	80.3			74.2			6.1			136.5			126.8			9.7
Income (taxes)	(27.3		)	(25.1		)	(2.2		)	(44.6		)	(42.3		)	(2.2		)
Valencia non-controlling interest	(3.7		)	(3.7		)	—			(10.9		)	(11.1		)	0.2
Preferred stock dividend requirements	(0.1		)	(0.1		)	—			(0.4		)	(0.4		)	—
Segment earnings	$	49.2		$	45.2		$	4.0		$	80.6		$	73.0		$	7.6

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



	2014/2015 Change
	Three Months Ended September 30,									Nine Months Ended September 30,
	Electric									Electric
	Operating			Cost of						Operating			Cost of
	Revenues			Energy			Margin			Revenues			Energy			Margin
	(In millions)
Customer usage/load	$	(3.3	)	$	—		$	(3.3	)	$	(6.7	)	$	—		$	(6.7	)
Weather	4.2			—			4.2			0.2			—			0.2
Transmission	(1.2		)	(0.1		)	(1.1		)	(3.4		)	(0.1		)	(3.3		)
FPPAC	(4.1		)	(4.1		)	—			18.2			18.2			—
Economy energy service	(0.7		)	(0.7		)	—			(3.5		)	(3.4		)	(0.1		)
Rio Bravo purchase	—			(0.3		)	0.3			—			(3.6		)	3.6
Unregulated margin	(0.2		)	(0.3		)	0.1			(0.8		)	(0.7		)	(0.1		)
Wholesale contracts	(0.5		)	(0.5		)	—			(5.5		)	(2.1		)	(3.4		)
Energy efficiency rider	0.8			—			0.8			1.2			—			1.2
Renewable energy rider	2.7			0.6			2.1			5.5			1.6			3.9
Net unrealized economic hedges	1.5			(0.1		)	1.6			(1.1		)	0.2			(1.3		)
Non-FPPAC off-system activity	(2.1		)	(1.4		)	(0.7		)	(6.4		)	(6.1		)	(0.3		)
El Paso Natural Gas refund	—			—			—			—			(4.2		)	4.2
Other	1.3			(2.5		)	3.8			(0.3		)	(4.9		)	4.5
Net change	$	(1.6	)	$	(9.4	)	$	7.8		$	(2.6	)	$	(5.1	)	$	2.4

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



	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Change			2015			2014			Change
	(In millions, except customers)
Residential	$	131.0		$	127.2		$	3.8		$	331.8		$	317.6		$	14.2
Commercial	128.1			127.7			0.4			338.8			326.6			12.2
Industrial	21.3			21.3			—			57.2			54.4			2.8
Public authority	8.0			8.0			—			19.8			19.2			0.6
Economy service	8.7			9.3			(0.6		)	26.5			29.9			(3.4		)
Other retail	(0.6		)	(1.2		)	0.6			3.5			4.0			(0.5		)
Transmission	8.4			9.5			(1.1		)	24.9			28.3			(3.4		)
Firm-requirements wholesale	7.4			8.1			(0.7		)	22.9			30.0			(7.1		)
Other sales for resale	16.4			21.9			(5.5		)	46.7			63.5			(16.8		)
Mark-to-market activity	4.7			3.2			1.5			(1.3		)	(0.1		)	(1.2		)
	$	333.4		$	335.0		$	(1.6	)	$	870.8		$	873.4		$	(2.6	)
Average retail customers (thousands)	515.3			511.4			3.9			514.4			510.9			3.5

The following table shows GWh sales by customer class:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015	2014	Change		2015	2014	Change
	(Gigawatt hours)
Residential	958.0	936.1	21.9		2,436.7	2,442.2	(5.5	)
Commercial	1,060.1	1,069.5	(9.4	)	2,882.2	2,942.7	(60.5	)
Industrial	254.7	254.6	0.1		720.3	737.2	(16.9	)
Public authority	72.8	74.3	(1.5	)	182.7	189.0	(6.3	)
Economy service	195.8	188.8	7.0		591.8	572.4	19.4
Firm-requirements wholesale	108.3	105.7	2.6		322.9	415.9	(93.0	)
Other sales for resale	515.8	602.0	(86.2	)	1,527.4	1,725.0	(197.6	)
	3,165.5	3,231.0	(65.5	)	8,664.0	9,024.4	(360.4	)

During 2015, PNM continued to be impacted by a 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. The rolling twelve-month average job growth in Albuquerque is currently at 1.4%, with several local businesses making announcements of new jobs, although the national average is 2.0%. New Mexico housing prices increased 1.5% in the first quarter of 2015 compared to the first quarter of 2014. Overall economic growth continues to be slow. However, PNM experienced an increase in the average number of retail customers of 0.8% and 0.7% for the three and nine months ended September 30, 2015 compared to 2014. PNM’s weather normalized retail KWh sales were 1.7% and 1.4% lower for the three and nine months ended September 30, 2015 compared to 2014, which decreased revenues and margin $3.3 million and $6.7 million in 2015 compared to 2014. Warmer weather in the third quarter of 2015 compared to 2014 increased revenues and margin $4.2 million for the three months ended September 30, 2015. This was partially offset by milder weather in the first two quarters of 2015 compared to 2014, resulting in increased revenues and margin of $0.2 million for the nine months ended September 30, 2015. For the three months ended September 30, 2015, cooling degree days were 14.5% higher than in 2014. For the nine months ended September 30, 2015 compared to 2014 heating degree days were 0.6% lower and cooling degree days were higher 3.1%. Cooling degree days only have a minor impact on the first quarter of any year, whereas heating degree days only have a minor impact on the second and third quarters.

For the three and nine months ended September 30, 2015, transmission revenues decreased $1.2 million and $3.4 million and margin decreased $1.1 million and $3.3 million compared to 2014. These decreases primarily resulted from the expiration

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of long-term point-to-point contracts aggregating $0.7 million and $2.5 million for the three and nine months ended September 30, 2015 compared to 2014. Lower short-term point-to-point transmission revenues decreased revenues and margin $0.5 million and $1.2 million for the three and nine months ended September 30, 2015 compared to 2014. The decreases were partially offset by a May 2014 rate increase under PNM’s formula-based transmission rate case, which increased revenues $0.2 million and $0.7 million during the three and nine months ended September 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 of quarterly changes in the rate charged under the rider, PNM’s revenues increased in nine months ended September 30, 2015 but decreased in the three months ended September 30, 2015 compared to 2014. These changes in revenue 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 margin. Although revenue from this customer decreased for the three and nine months ended September 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 $0.3 million and $3.6 million for the three and nine months ended September 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 2015 resulted in lower revenues of $0.2 million and 0.8 million for the three and nine months ended September 30, 2015 than in 2014. Lower nuclear fuel costs decreased cost of energy $0.3 million and $1.0 million for the three and nine months ended September 30, 2015 compared to 2014. Nuclear spent fuel reimbursements from the DOE decreased cost of energy and increased margin $1.9 million for the nine months ended September 30, 2015 compared to 2014. See Note 11. In addition, gas imbalance settlements lowered cost of energy $2.1 million in the nine months ended September 30, 2014, which settlements did not recur in 2015.

PNM’s contract with Gallup, previously its second largest wholesale generation customer, expired on June 29, 2014. For the nine months ended September 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 August 2015 includes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. See Note 12. Revenues and cost of energy associated with other wholesale contracts decreased $0.5 million for the three months ended September 30, 2015, primarily resulting from lower fuel costs passed through to wholesale customers.

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. For the three and nine months ended September 30, 2015, this rider increased revenues by $2.7 million and $5.5 million compared to 2014. Revenues under this rider include a return on investment of $1.8 million and $5.4 million for the three and nine months ended September 30, 2015 compared to $1.2 million and $3.7 million for 2014. Cost of energy, reflecting purchase of RECs, increased $0.6 and $1.6 million for the three and nine months ended September 30, 2015 compared to 2014. Revenue and margin from PNM’s energy efficiency rider increased $0.8 million and $1.2 million for the three and nine months ended September 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 gains of $4.8 million for the three months ended September 30, 2015 compared to unrealized gains of $3.3 million for the three months ended September 30, 2014 increased margin by $1.6 million. Unrealized losses of $1.2 million for the nine months ended September 30, 2015 compared to unrealized gains of $0.1 million for the nine months ended September 30, 2014 decreased margin by $1.3 million.

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Reduced off-system sales and off-system purchases not passed through PNM’s FPPAC decreased revenue $2.1 million and $6.4 million and decreased cost of energy $1.4 million and $6.1 million for the three and nine months ended September 30, 2015 compared to 2014. The reductions were due to less power being available for off-system sales, primarily related to SJGS and lower market prices.

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 nine months ended September 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 nine months ended September 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 part of the approval of PNM’s FPPAC, 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 nine months ended September 30, 2014, which included amounts from July 1, 2013 through September 30, 2014. For the three and nine months ended September 30, 2015, PNM retained revenues of $0.2 million and $0.5 million under this provision.

For the three months ended September 30, 2015, operating expenses increased $3.2 million compared to 2014. Higher maintenance expenses at SJCC, Four Corners, and PVNGS plants of $1.6 million, $1.1 million, and $0.4 million were partially offset by lower maintenance expenses at gas fired plants of $0.3 million. Higher healthcare costs of $2.1 million and higher labor costs of $0.8 million increased operating expenses for the three months ended September 30, 2015 compared to 2014. Lower capitalized administrative and general expenses of $0.4 million increased operating expenses for the three months ended September 30, 2015. In addition, an increase in environmental expenses of $0.6 million and higher energy efficiency expenses, which are recovered through the revenue rider described above, of $0.8 million increased operating expenses for the three months ended September 30, 2015. These expenses were partially offset by 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, decreasing operating expenses $4.1 million. The termination of the lease for the 40% interest in the EIP transmission line on April 1, 2015 also decreased operating expenses $0.7 million for the three months ended September 30, 2015 compared to 2014.

For the nine months ended September 30, 2015, operating expenses decreased $3.2 million compared to 2014. The reduced rentals on the PVNGS Unit 1 leases decreased operating expenses $11.7 million for the nine months ended September 30, 2015 compared to 2014. Higher maintenance expenses at SJCC, Four Corners, PVNGS, and natural gas-fired plants of $1.6 million, $2.5 million, $2.1 million, and $0.3 million increased operating expenses. Lower pension expenses of $1.0 million and higher capitalized administrative and general expenses of $1.3 million, due to increased capital spending, reduced operating expenses for the nine months ended September 30, 2015 compared to 2014. In the nine months ended September 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 nine months ended June 30, 2015 compared to 2014. In addition, the termination of the EIP lease decreased operating expenses $1.4 million in the nine months ended September 30, 2015. Higher healthcare costs of $2.5 million and higher labor costs of $0.7 million increased operating expenses for the nine months ended September 30, 2015. The increase in environmental expenses of $0.6 million and higher energy efficiency expenses of $1.7 million increased expenses for the nine months ended September 30, 2015. During the nine months ended September 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 $1.7 million

Depreciation and amortization expense increased $1.5 million and $4.8 million for the three and nine months ended September 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 $2.7 million and $8.4 million for the three and nine months ended September 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) $1.6 million and $3.9 million in the three and nine months ended September 30, 2015 compared to 2014. Higher fees and taxes on the NDT decreased other income (deductions) by $0.9 million and $2.1 million in the three and nine months ended September 30, 2015. Income of $1.4 million and $3.4 million from refined coal (a third-party pre-treatment process) at SJGS increased other income (deductions) for the three and nine months ended September

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30, 2015 compared to 2014. Higher equity AFUDC of $2.2 million and $3.5 million due to increased levels of construction also increased other income (deductions) in 2015. PNM recognized a gain of $1.1 million in the nine months ended September 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. Changes in the amounts of losses on retirements of PVNGS Unit 3 assets decreased other income (deductions) $0.1 million for the three months ended September 30, 2015 compared to 2014, but increased other income (deductions) $0.5 million for the nine months ended September 30, 2015. Interest income on PVNGS lessor notes decreased $0.6 million and $1.8 million during the three and nine months ended September 30, 2015 compared to 2014 due to lower outstanding principal balances under the notes.

Interest charges decreased $0.3 million and $0.4 million for the three and nine months ended September 30, 2015 compared to 2014 due to higher debt AFUDC, partially offset by higher cost of borrowings for the $250.0 million Senior Unsecured Notes issued on August 11, 2015 Note 9 compared to the debt paid off with the proceeds of that offering.

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 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 September 30,									Nine Months Ended September 30,
	2015			2014			Change			2015			2014			Change
	(In millions)
Electric operating revenues	$	84.0		$	79.0		$	5.0		$	232.4		$	215.6		$	16.8
Cost of energy	18.5			17.4			1.1			54.6			50.2			4.4
Margin	65.4			61.6			3.8			177.7			165.4			12.3
Operating expenses	22.8			22.3			0.5			65.3			63.7			1.6
Depreciation and amortization	15.0			13.4			1.6			42.1			37.3			4.8
Operating income	27.7			25.9			1.8			70.3			64.4			5.9
Other income (deductions)	0.7			0.8			(0.1		)	2.8			1.5			1.3
Net interest charges	(6.9		)	(6.9		)	—			(20.6		)	(20.1		)	(0.5		)
Segment earnings before income taxes	21.5			19.8			1.7			52.4			45.8			6.6
Income (taxes)	(7.8		)	(7.4		)	(0.4		)	(19.2		)	(17.1		)	(2.1		)
Segment earnings	$	13.7		$	12.4		$	1.3		$	33.2		$	28.7		$	4.5

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



	2014/2015 Change
	Three Months Ended September 30,								Nine Months Ended September 30,
	Electric								Electric
	Operating			Cost of					Operating			Cost of
	Revenues			Energy		Margin			Revenues			Energy		Margin
	(In millions)
Rate increases	$	2.2		$	—	$	2.2		$	6.4		$	—	$	6.4
Customer usage	0.1			—		0.1			1.7			—		1.7
Customer growth	0.5			—		0.5			1.2			—		1.2
Weather	0.8			—		0.8			0.6			—		0.6
Recovery of third-party transmission costs	1.1			1.1		—			4.4			4.4		—
AMS surcharge	0.8			—		0.8			3.6			—		3.6
Energy efficiency incentive bonus	(0.8		)	—		(0.8		)	(0.8		)	—		(0.8		)
Other	0.3			—		0.3			(0.3		)	—		(0.3		)
Net change	$	5.0		$	1.1	$	3.8		$	16.8		$	4.4	$	12.3

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015		2014		Change		2015		2014		Change
	(In millions, except consumers)
Residential	$	39.4	$	36.6	$	2.8	$	94.1	$	89.5	$	4.6
Commercial	26.0		25.1		0.9		76.1		73.5		2.6
Industrial	4.1		3.9		0.2		12.1		11.1		1.0
Other	14.5		13.4		1.1		50.1		41.5		8.6
	$	84.0	$	79.0	$	5.0	$	232.4	$	215.6	$	16.8
Average consumers (thousands) ⁽¹⁾	242.2		238.9		3.3		241.2		237.7		3.5


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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015	2014 ⁽¹⁾	Change		2015	2014 ⁽¹⁾	Change
	(Gigawatt hours)
Residential	993.2	938.8	54.4		2,338.3	2,227.9	110.4
Commercial	767.5	737.2	30.3		2,020.3	1,944.7	75.6
Industrial	694.2	709.6	(15.4	)	2,083.4	2,014.2	69.2
Other	26.5	26.4	0.1		76.1	75.9	0.2
	2,481.4	2,412.0	69.4		6,518.1	6,262.7	255.4


⁽¹⁾	The 2014 GWh amounts reflect a reclassification of 5.6 GWh and 18.1 GWh from industrial to commercial for the three and nine months ended September 30, 2014 to be consistent with the current year presentation.

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For the three and nine months ended September 30, 2015, revenues and margin increased by $2.2 million and $6.4 million compared to 2014 due to transmission cost of service rate increases in March 2014, September 2014, March 2015, and September 2015. See Note 12. TNMP’s weather normalized retail KWh sales increased 1.5% and 2.7% for the three and nine months ended September 30, 2015 compared to 2014. Higher weather normalized usage per customer increased revenues and margin by $0.1 million and $1.7 million for the three and nine months ended September 30, 2015 compared to 2014. Warmer weather in the summer months of 2015 compared to 2014, partially offset by milder weather in the winter months, increased revenues and margins by $0.8 million and $0.6 million for the three and nine months ended September 30, 2015 compared to 2014. For the three and nine months ended September 30, 2015 compared to 2014, cooling degree days were 8.2% higher and 5.1% higher and heating degree days were flat and 3.4% lower. TNMP also experienced positive year to date average customer growth of 1.5%, increasing revenues and margin by $0.5 million and $1.2 million for the three and nine months ended September 30, 2015 compared to 2014.

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 $1.1 million and $4.4 million for the three and nine months ended September 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 $1.1 million and $4.4 million for the three and nine months ended September 30, 2015 compared to 2014.

TNMP earned energy efficiency incentive bonuses for having achieved demand savings for the 2013 and 2014 program years that exceeded its goal. The $1.5 million incentive bonus for the 2013 program year was approved by the PUCT on September 11, 2014 and the $0.7 million incentive bonus for the 2014 program year was approved by the PUCT on September 11, 2015. The lower incentive bonus decreased revenues and margin by $0.8 million for the three and nine months ended September 30, 2015. See Note 12.

The AMS surcharge increased revenues and margin by $0.8 million and $3.6 million for the three and nine months ended September 30, 2015 compared to 2014. Other in the table above, which includes recovery of the CTC, rate case expenses, and energy efficiency programs, was slightly higher for the three months ended September 30, 2015 and slightly lower for the nine months ended September 30, 2015 compared to 2014. Changes in these revenues were offset by changes in operating and depreciation and amortization expenses.

Operating expenses increased $0.5 million and $1.6 million for the three and nine months ended September 30, 2015 compared to 2014. Higher employee healthcare costs of $0.8 million and $1.5 million, higher property taxes, resulting from higher plant in service balances, of $0.4 million and $1.1 million, and higher street rental taxes of $0.2 million and $0.3 million for the three and nine months ended September 30, 2015 increased operating expenses compared to 2014. These increases were partially offset by higher capitalization of administrative and general expenses related to higher levels of construction expenditures, which decreased operating expenses by $1.3 million for the three and nine months ended September 30, 2015 compared to 2014. In addition, property and casualty claims were $0.3 million higher for the three months ended September 30, 2015 but $0.3 million lower for the nine months ended September 30, 2015.

Depreciation and amortization increased $1.6 million and $4.8 million for the three and nine months ended September 30, 2015 compared to 2014. Depreciation expense associated with the AMS deployment, which is recovered through the AMS surcharge, increased $0.7 million and $2.3 million for the three and nine months ended September 30, 2015 compared to 2014 due to increased AMS deployment. Amortization expense associated with the CTC, which is recovered through the CTC surcharge, increased $0.3 million and $0.7 million for the three and nine months ended September 30, 2015 compared to 2014. In addition, an increase in utility plant in service increased depreciation by $0.6 million and $1.8 million for the three and nine months ended September 30, 2015 compared to 2014.

Other income (deductions) decreased $0.1 million and increased $1.3 million for the three and nine months ended September 30, 2015, primarily due to changes in contributions in aid of construction.

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

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Corporate and Other

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



	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Change			2015			2014			Change
	(In millions)
Total revenues	$	—		$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—			—
Margin	—			—			—			—			—			—
Operating expenses	(3.6		)	(3.7		)	0.1			(11.1		)	(10.2		)	(0.9		)
Depreciation and amortization	3.4			3.3			0.1			10.5			9.5			1.0
Operating income	0.1			0.3			(0.2		)	0.6			0.7			(0.1		)
Other income (deductions)	(0.5		)	(0.6		)	0.1			(3.0		)	(1.6		)	(1.4		)
Net interest charges	(0.8		)	(3.2		)	2.4			(6.6		)	(9.6		)	3.0
Segment earnings (loss) before income taxes	(1.2		)	(3.4		)	2.2			(8.9		)	(10.4		)	1.5
Income (taxes) benefit	(0.7		)	1.5			(2.2		)	2.1			6.0			(3.9		)
Segment earnings (loss)	$	(1.9	)	$	(1.9	)	$	—		$	(6.8	)	$	(4.4	)	$	(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.

Depreciation expense increased in the three and nine months ended September 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) includes losses of $1.1 million recorded in the three months ended March 31, 2015 for 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.

Income taxes (benefit) is impacted by the impairments of wind energy production tax credits of $1.0 million and $1.1 million (net of federal income tax benefit) and New Mexico state net operating losses of $0.1 million and $0.4 million (net of federal income tax benefit) in the three and nine months ended September 30, 2015. 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 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.

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LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

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



	Nine Months Ended September 30,
	2015			2014			Change
	(In millions)
Net cash flows from:
Operating activities	$	335.6		$	326.2		$	9.4
Investing activities	(387.2		)	(311.7		)	(75.5		)
Financing activities	50.3			11.3			39.0
Net change in cash and cash equivalents	$	(1.3	)	$	25.9		$	(27.2	)

Changes in PNMR’s cash flows 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. Cash flows from operating activities also increased $44.4 million in the nine months September 30, 2015 compared to 2014 related to the collection of amounts deferred in PNM’s FPPAC resulting from the cap on amounts passed through to ratepayers prior to June 30, 2014. In addition, contributions to PNMR’s pension and postretirement benefit plans were $29.7 million higher in the nine months ended September 30, 2015 than in 2014.

The changes in PNMR’s cash flows from investing activities relate primarily to an increase of $118.2 million in utility plant additions in the nine months ended September 30, 2015 compared to 2014. Utility plant additions at PNM were $101.6 million higher in the nine months ended September 30, 2015 compared to 2014, including increases in generation additions of $90.0 million and transmission and distribution additions of $15.3 million, offset by lower nuclear fuel purchases of $3.7 million. TNMP utility plant additions increased $1.6 million in the nine months ended September 30, 2015 compared to 2014, including increases in transmission and distribution additions of $5.3 million and a decrease in AMS additions of $3.8 million. Corporate plant additions increased $15.1 million in the nine month ended September 30, 2015 compared to 2014, including increases for computer hardware and software additions of $11.3 million and PNMR Development utility plant additions of $3.8 million. Investing activities in 2014 also includes $36.2 million for the acquisition of Rio Bravo as discussed in Note 5.

The changes in PNMR’s cash flows from financing activities include a $46.2 million increase in net short-term borrowing repayments in the nine months ended September 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 $25.0 million of additional long-term borrowings under the PNM Multi-draw Term Loan. PNMR used portions of the proceeds to repay $118.8 million of 9.25% senior unsecured notes that matured on May 15, 2015 and for general corporate purposes. In 2015, PNM also issued $250.0 million aggregate principal amount of its 3.850% Senior Unsecured Notes due 2025. PNM used the proceeds to repay the $175.0 million PNM 2014 Term Loan agreement and outstanding borrowings under the PNM Revolving Credit Facility, the PNM New Mexico Credit Facility, and PNM’s intercompany loan from PNMR. In 2015, PNM also successfully remarketed $39.3 million of senior unsecured notes, pollution control revenue bonds. 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

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•	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. In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 2.027% for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018.

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 September 30, 2015, interest rates on outstanding borrowings were 1.05% for the PNMR Term Loan Agreement, 1.21% for the PNMR 2015 Term Loan Agreement, and 0.78% 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 September 30, 2015 , are:



	2015		2016-2019		Total
	(In millions)
Construction expenditures	$	576.5	$	1,706.1	$	2,282.6
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	$	640.7	$	1,963.1	$	2,603.8

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 $60.0 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 $179.8 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, peaking resources to meet needs outlined in PNM’s current IRP, environmental upgrades at Four Corners of $91.4 million, the purchase of the leased portion of the EIP on April 1, 2015, and the purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases in 2016. Expenditures for the SJGS and Four Corners environmental upgrades are estimated to be $63.8 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.

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During the nine months ended September 30, 2015 , PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements, additional term loan borrowings, and the issuance of the 3.850% Senior Unsecured Notes by PNM.

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 was repaid on August 12, 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. 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 have been extended to expire in October 2020 and the TNMP Revolving Credit Facility that expires in September 2018. The PNMR Revolving Credit Facility has a financing capacity of $300.0 million, the PNM Revolving Credit Facility has a financing capacity of $400.0 million, and the TNMP Revolving Credit Facility has a financing capacity of $75.0 million. 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 $25.6 million during the three and nine months ended September 30, 2015 . Borrowings under the PNM Revolving Credit Facility ranged from zero to $48.4 million during the three and nine months ended September 30, 2015 . Borrowings under the PNM New Mexico Credit Facility ranged from zero to $20.0 million during the three and nine months ended September 30, 2015 . Borrowings under the TNMP Revolving Credit Facility ranged from zero to $37.0 million during the three and nine months ended September 30, 2015 . At September 30, 2015 , the average interest rate was 1.69% under the PNMR Revolving Credit Facility. At September 30, 2015 , TNMP had $48.5 million in borrowings from PNMR under its intercompany loan agreements.

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

In addition to its internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing to fund its capital requirements during the 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

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debt rating of TNMP to A1 from A2, and changed the outlook for PNMR, PNM, and TNMP to stable from positive. As of October 23, 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.

A summary of liquidity arrangements as of October 23, 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 October 23, 2015:
Revolving credit facility	$	—	$	—	$	20.0	$	20.0
PNM New Mexico Credit Facility	—		—		—		—
Letters of credit	6.2		3.2		0.1		9.5

Total short-term debt and letters of credit	6.2		3.2		20.1		29.5

Remaining availability as of October 23, 2015	$	293.8	$	446.8	$	54.9	$	795.5
Invested cash as of October 23, 2015	$	11.0	$	34.1	$	—	$	45.1

The above table excludes intercompany debt. As of October 23, 2015 , TNMP had $36.8 million in borrowings from PNMR under an intercompany loan agreement. 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 2018. PNM has a shelf registration statement, which expires in May 2017, with capacity for up to $250.0 million of senior unsecured notes.

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

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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.

Capital Structure

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



	September 30, 2015		December 31, 2014
PNMR
PNMR common equity	45.4	%	46.4	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	54.3	%	53.3	%
Total capitalization	100.0	%	100.0	%

PNM
PNM common equity	44.6	%	45.7	%
Preferred stock	0.4	%	0.4	%
Long-term debt	55.0	%	53.9	%
Total capitalization	100.0	%	100.0	%

TNMP
Common equity	59.6	%	58.9	%
Long-term debt	40.4	%	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 included approximately 6.7 million metric tons of CO ₂ , 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 CO ₂ .

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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 3 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 43 MW at September 30, 2015 and is expected to grow to over 45 MW by the end of 2015. PNM’s 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 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 CO ₂ 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.

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 the 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. 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. EPA published final rules approving the RSIP and withdrawing the previously issued FIP in the Federal Register on October 9, 2014 and the rules became effective on November 10, 2014.

Because of PNM’s dependence on fossil-fueled generation, 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. 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. PNM’s service areas also experience periodic high winds, forest fires, and severe thunderstorms. 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. Climate changes are generally not expected to have material consequences to the Company in the near-term.

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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 (CO ₂ , 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 the construction of new emission units that emit GHG of at least 100,000 tons per year in CO ₂ equivalents (even if PSD is not triggered for other pollutants). In addition, modifications at existing major-emitting facilities that increase GHG by at least 75,000 tons per year in CO ₂ equivalents 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 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 his 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

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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. EPA’s reproposed GHG NSPS for new sources applied 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 as proposed would require state-specific CO ₂ emission reduction goals based on EPA’s finding of the best system of emissions reductions (“BSER”). The proposed BSER was based on four “building blocks”: 1) a 6% heat rate improvement to coal-fired generation units; 2) a shift in electrical generation from coal-fired and oil/gas-fired EGUs to natural gas combined cycle units (“NGCCs”) such that the NGCCs would operate 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 might be retired; and 4) increases to demand-side energy efficiency programs. Comments on the proposed rule were due on 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 Section 111(b). Under the proposed rule there were two alternatives for EGUs: 1) a CO ₂ emission limit based on the unit’s best historic annual CO ₂ emissions plus an additional 2% reduction or 2) an emission limit dependent on when the unit was 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 CO ₂ 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 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 updated the expected deadline for the agency to issue the 111(d) plan to midsummer 2015.

On August 3, 2015, EPA issued its final standards to limit CO ₂ emissions from power plants. Three separate but related actions took place: (1) the final Carbon Pollution Standards for new, modified, and reconstructed power plants were established (under Section 111(b)); (2) the final Clean Power Plan was issued to set standards for carbon emission reductions from existing power plants (under Section 111(d)); and (3) a proposed federal plan associated with the final Clean Power Plan was released.

EPA’s final rule to limit GHG emissions from new, modified, and reconstructed power establishes standards based upon certain, specific conditions. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, the EPA is finalizing a standard of 1,000 lb CO ₂ /MWh-gross based on efficient natural gas combined cycled technology as the BSER. Alternatively, owners and operators of base load natural gas-fired combustion turbines may elect to comply with a standard based on an output of 1,030 lb CO ₂ /MWh-net. A new source is any newly constructed fossil fuel-fired power plant that commenced construction after January 8, 2014.

The final standards for coal-fired power plants vary depending on whether the unit is new, modified, or reconstructed. The BSER for new steam units is a supercritical pulverized coal unit with partial carbon capture and storage. Based on that technology, new coal-fired units will be required to meet an emissions standard equal to 1,400 lbs CO ₂ /MWh from the beginning of the power plant’s life. The BSER for modified units is based on each affected unit’s own best potential performance. Standards will be in the form of an emission limit in pounds of CO ₂ per MWh, which will apply to units with modifications resulting in an increase of hourly CO ₂ emissions of more than 10% relative to the emissions of the most recent five years from that unit. The BSER for reconstructed coal-fired power units is the performance of the most efficient generating technology for these types of units. Final emissions standards depend on heat input. Sources with heat input greater than 2,000 MMBTU/hour would be required to meet

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an emission limit of 1,800 lbs CO ₂ /MWh-gross, and sources with a heat input of less than or equal to 2,000 MMBTU/hour would be required to meet an emission limit of 2,000 lbs CO ₂ /MWh-gross.

The final Clean Power Plan rule changed significantly in structure from the June 2014 proposed rule. Changes include delaying the first compliance date by two years from 2020 to 2022; adopting a new approach to calculating the emission targets which resulted in different state goals than those originally proposed; adding a reliability safety valve; and proposing rewards for early reductions. The rule establishes two numeric “emission standards” - one for “fossil-steam” units (coal- and oil-fired units) and one for natural gas-fired units (combined cycle only). The emission standards are based on emission reduction opportunities that EPA deemed achievable using technical assumptions for three “building blocks:” efficiency improvements at coal-fired EGUs, displacement of affected EGUs with renewable energy, and displacement of coal-fired generation with natural gas-fired generation. The final standards are 1,305 lb/MWH for fossil-steam units and 771 lb/MWH for gas units, both of which phase in over the period 2022-2030. To facilitate implementation, EPA converted the emission standards into state goals. Each state’s goal reflects the average state-wide emission rate that all of the state’s affected EGUs would meet in the aggregate if each one achieved the emission standards alone based upon a weighted average of each state’s unique mix of affected units.

Under the final rule, states are required to make initial plan submissions to EPA by September 6, 2016. EPA will grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension must submit an update to EPA in 2017. All final state plans are due by 2018. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide, but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. Plans using state measures may only be used with mass-based goals and must include “backstop” federally enforceable standards for EGUs that will become effective if the state measures fail to achieve the expected level of emission reductions.

The Clean Power Plan also proposes a Clean Energy Incentive Program designed to award credits for early development of certain renewable energy and energy efficiency programs that displace fossil generation in 2020 and 2021 prior to the compliance obligation taking effect in 2022. In addition, the Clean Power Plan contains a reliability safety valve for individual power plants. The reliability safety valve allows for a 90-day relief from CO ₂ emissions limits if generating units need to continue to operate and release excess emissions during emergencies that could compromise electric system reliability.

As discussed above, EPA issued a proposed Federal Plan in association with the Clean Power Plan. Under Section 111(d), EPA is authorized to issue a federal plan for states that do not submit an approvable state plan. EPA indicates that states may voluntarily adopt the Federal Plan in whole or in part as its state plan. EPA explains in its communications that the proposed Federal Plan will be released in advance of the deadline for submission of state plans to provide regulatory certainty to states that fail to submit approvable plan. The proposed Federal Plan will apply emission reduction obligations directly on affected EGUs. The plan presents two approaches: a rate-based emissions trading program and a mass-based emissions trading program. EPA indicates that it will choose only one of these approaches in the final Federal Plan. However, the proposed rule will offer both approaches for states to use as models in their own plans. EPA intends to finalize both the rate-based and mass-based model trading rules in summer 2016.

PNM is currently reviewing the new carbon emission reductions standards set forth for EGUs in EPA’s August 3, 2015 regulatory actions. The Clean Power Plan was published on October 23, 2015. Multiple states, utilities, and trade groups subsequently filed petitions for review and motions to stay in the D.C. Circuit. These actions will impact PNM’s existing and future fossil-fueled EGUs. Impacts could involve investments in additional renewables and energy efficiency programs, efficiency improvements, and/or control technologies at the fossil-fueled EGUs. Under an emissions rate or mass based trading program, PNM may be required to purchase credits or allowances to comply with New Mexico’s final state plan. 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. The only 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. Additional GHG control technologies for existing EGUs may become viable in the future. The costs of purchasing carbon credits or allowances, making improvements, or installing new technology could impact the economic viability of some plants. PNM estimates that implementation of the RSIP for BART at SJGS, which requires the installation of SNCRs on Units 1 and 4 by early 2016 and the retirement of SJGS Units 2 and 3 by the end of 2017, should provide a significant step for New Mexico to meet its ultimate compliance with Section 111(d). PNM is unable to predict the impact of this rule on its fossil-fueled generation.

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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 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 CO ₂ 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 CO ₂ 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 CO ₂ 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 CO ₂ per MWh the utility emits. Credits would be retired such that 3% per year reductions are achieved from the baseline year until 2035 unless a participating utility elects to terminate the program at the end of 2023. Credits would not expire and could be banked. An advisory committee of interested stakeholders would monitor the program. In addition, utilities would be allowed to satisfy their obligations by funding NMPRC approved energy efficiency programs. There has been no further action on this matter at the NMPRC.

International Accords

The United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was negotiated at the 1992 United Nations Conference on Environment and Development (informally known as the Earth Summit) and entered into force in March 1994. The objective of the treaty is to “stabilize greenhouse gas concentrations in the

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atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.” Parties, including the United States, have been meeting annually in Conferences of the Parties (“COP”) to assess progress in meeting the objectives of the UNFCCC. This assessment process led to the negotiation of the Kyoto Protocol in the mid-1990s. The Protocol, which was agreed to in 1997 and established legally binding obligations for developed countries to reduce their GHG emissions, was never ratified by the United States. PNM 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 agreement involving commitment by all nations to begin reducing carbon emissions by 2020. The new agreement, being negotiated by the Ad Hoc Group on the Durban Platform for Enhanced Action, would supplant the Kyoto Protocol. In November 2014, President Obama announced the United States’ commitment to reduce greenhouse gas emissions by 26%-28% from 2005 levels by the year 2025, which would put the United States on a path to achieve economy-wide reductions of around 80% by 2050. As part of the process for developing the new global climate agreement, the United States formally submitted its Intended Nationally Determined Contribution (“INDC”) to the UNFCCC Secretariat on March 31, 2015, which reflected no change from the November 2014 announcement. To date, INDCs have been submitted by nearly 150 nations, including the United States and the European Union. PNM will continue to monitor the United States participation in international accords. However, the Obama administration’s GHG emissions reduction target for the electric utility industry will be based on EPA’s final GHG regulations for new, existing, and modified and reconstructed sources, 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 729 to modify certain aspects of the MOD standards, including MOD-001 and MOD-029. The modifications to this standard would retire MOD-029 and require each transmission operator to determine and develop methodology for TTC values for MOD-001.

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

In July 2011, FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development 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

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and six other WestConnect FERC jurisdictional utilities’ compliance filings partially accepting 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 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 was to expire as of May 1, 2015. Negotiations for a new agreement with the

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IBEW began in January 2015 and the parties agreed to extend the collective bargaining agreement should an agreement not be reached by May 1, 2015. The agreement continued in effect during negotiations unless either the union or PNM gave a thirty days' written notice of termination. On July 22, 2015, PNM gave notice of termination, effective August 24, 2015. PNM and the union continue to negotiate a new agreement. While the Company is optimistic that an 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 contract 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 September 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.

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.

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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 and judicial action with regard to the proposed early retirement of SJGS Units 2 and 3


•	Uncertainty regarding obtaining required regulatory approvals, and the timing of such approvals, for 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, including the federal Clean Power Plan


•	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, advanced 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


•	Counterparty credit and performance risk and the effectiveness of risk management


•	Changes in applicable accounting principles or policies

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

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SECURITIES ACT DISCLAIMER

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

WEBSITES

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

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.

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

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•	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 nine months ended September 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.



	Nine Months Ended
	September 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	(8,379		)	2,005
Changes in fair value	7,127			(1,938		)
Net mark-to-market change recorded in earnings	(1,252		)	67
Net change recorded as regulatory assets and liabilities	235			(166		)
Net fair value at end of period	$	8,529		$	3,174

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

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



	Settlement Dates
	2015		2016		2017
	(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—	$	—
Prices provided by other external sources	3,297		2,604		2,628
Prices based on models and other valuations	—		—		—
Total	$	3,297	$	2,604	$	2,628

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

PNM measures VaR for the positions in its wholesale portfolio (not covered by the FPPAC). For the nine months ended September 30, 2015 , the high, low, and average VaR amounts were $2.6 million, $0.9 million, and $1.5 million. For the year

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ended December 31, 2014 , the high, low, and average VaR amounts were $2.1 million, $0.6 million, and $0.9 million. At September 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 nine months ended September 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 September 30, 2015 will mature in less than two years, except for $0.7 million, which will mature in the fourth quarter of 2017.

Schedule of Credit Risk Exposure

September 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	$	3,515	1	$	2,916
Non-investment grade	—		—	—
Internal ratings:
Investment grade	6,520		1	5,729
Non-investment grade	9		—	—
Total	$	10,044		$	8,645


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

⁽²⁾

The Credit Risk Exposure is the gross credit exposure, including long-term contracts (other than firm-requirements wholesale customers), forward sales, and short-term sales. The exposure captures the amounts from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses. Gross exposures can be offset according to legally enforceable netting arrangements but are not reduced by posted credit collateral. At September 30, 2015 , PNMR held $0.1 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of September 30, 2015 was $5.7 million.

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

Interest Rate Risk

The majority of the Company’s long-term debt is fixed-rate debt and does not expose earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of PNMR’s consolidated long-term debt instruments would increase by 2.1%, or $47.6 million, if interest rates were to decline by 50 basis points from their levels at September 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 October 23, 2015 , PNMR, PNM, and TNMP had

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short-term debt outstanding of none, none, and $20.0 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 no borrowings outstanding under its $50.0 million PNM New Mexico Credit Facility at October 23, 2015 . The revolving credit facilities, the PNM New Mexico Credit Facility, the $125.0 million PNM Multi-draw Term Loan, the $100.0 million PNMR Term Loan Agreement, and the PNMR 2015 Term Loan Agreement bear interest at variable rates, which averaged 1.19% for the TNMP Revolving Credit Facility, 0.78% for the PNM Multi-draw Term Loan, 1.05% for the PNMR Term Loan Agreement, and 1.20% for the PNMR 2015 Term Loan Agreement on October 23, 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 $242.8 million at September 30, 2015 , of which 45.8% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at September 30, 2015 , the decrease in the fair value of the fixed-rate securities would be 3.4%, or $3.8 million.

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

Equity Market Risk

The investments held by PNM in trusts for decommissioning and reclamation include certain equity securities at September 30, 2015 . These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 42.4% of the securities held by various trusts as of September 30, 2015 . A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $10.3 million.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

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

Changes in internal controls

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

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•	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 – New Mexico General Rate Case


•	PNM – Proceeding Regarding Definition of Future Test Year


•	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.

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 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	Coal Supply Agreement dated July 1, 2015 between Westmoreland Coal Company and PNM

10.2	PNM	Underground Coal Sales Agreement Termination and Mutual Release Agreement dated July 1, 2015 among San Juan Coal Company, BHP Billiton New Mexico Coal, Inc., PNM, and Tucson Electric Coal Company

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10.3	PNM	San Juan Project Restructuring Agreement executed as of July 31, 2015 among PNM, Tucson Electric Coal Company, The City of Farmington, New Mexico, M-S-R Public Power Agency, The Incorporated County of Los Alamos, New Mexico, Southern California Public Power Authority, City of Anaheim, Utah Associated Municipal Power Systems, Tri-State Generation and Transmission Association, Inc., and PNMR Development and Management Corporation

10.4	PNM	Restructuring Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement made as of July 31, 2015 among PNM, Tucson Electric Power Company, The City of Farmington, New Mexico, M-S-R Public Power Agency, The Incorporated County of Los Alamos, New Mexico, Southern California Public Power Authority, City of Anaheim, Utah Associated Municipal Power Systems, Tri-State Generation and Transmission Association, Inc., and PNMR Development and Management Corporation

10.5	PNM	Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement made as of July 31, 2015 among PNM, Tucson Electric Power Company, The City of Farmington, New Mexico, The Incorporated County of Los Alamos, New Mexico, Utah Associated Municipal Power Systems, and PNMR Development and Management Corporation

10.6	PNMR	Fourth Amendment to Credit Agreement dated September 9, 2015 among PNMR, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent

10.7	PNMR	First Amendment to Term Loan Agreement dated September 9, 2015 among PNMR, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent

12.1	PNMR	Ratio of Earnings to Fixed Charges

12.2	PNM	Ratio of Earnings to Fixed Charges

12.3	TNMP	Ratio of Earnings to Fixed Charges

31.1	PNMR	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	PNMR	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3	PNM	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.4	PNM	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.5	TNMP	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.6	TNMP	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	PNMR	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2	PNM	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.3	TNMP	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS	PNMR, PNM, and TNMP	XBRL Instance Document

101.SCH	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Schema Document

101.CAL	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURE

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



		PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO TEXAS-NEW MEXICO POWER COMPANY
		(Registrants)


Date:	October 30, 2015	/s/ Joseph D. Tarry
		Joseph D. Tarry
		Vice President and Corporate Controller
		(Officer duly authorized to sign this report)

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Part I. Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 6. Exhibits

PNMXO 10-Q Quarter ended Sept. 30, 2015