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 SeptemberJune 30, 20172018

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”)YESüNO 
 Public Service Company of New Mexico (“PNM”)YESüNO 
 Texas-New Mexico Power Company (“TNMP”)YES NOü

(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).

 PNMRYESüNO 
 PNMYESüNO 
 TNMPYESüNO 



Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 
Large accelerated
filer
 
Accelerated
filer
 
Non-accelerated
filer (Do not check if a smaller reporting company)
 Smaller reporting company Emerging growth company
PNMR ü                         
PNM             ü           
TNMP             ü           

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £

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 20, 2017July 25, 2018, 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 20, 2017July 25, 2018 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 20, 2017July 25, 2018 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.



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
8
Condensed Consolidated Statements of Comprehensive Income
9
Condensed Consolidated Statements of Cash Flows
10
Condensed Consolidated Balance Sheets
12
Condensed Consolidated Statement of Changes in Equity
14
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
 
Condensed Consolidated Statements of Earnings
15
Condensed Consolidated Statements of Comprehensive Income
16
Condensed Consolidated Statements of Cash Flows
17
Condensed Consolidated Balance Sheets
19
Condensed Consolidated Statement of Changes in Equity
21
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
 
Condensed Consolidated Statements of Earnings
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
8489
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
126127
ITEM 4. CONTROLS AND PROCEDURES
130
PART II. OTHER INFORMATION
 
ITEM 1. LEGAL PROCEEDINGS
130
ITEM 1A. RISK FACTORS
130131
ITEM 5. OTHER INFORMATION
131
ITEM 6. EXHIBITS
131133
SIGNATURE
132135


GLOSSARY

Definitions:   
2014 IRP PNM’s 2014 IRP
2017 IRP PNM’s 2017 IRP
ABCWUA Albuquerque Bernalillo County Water Utility Authority
AEP OnSite PartnersAEP OnSite Partners, LLC, a subsidiary of American Electric Power, Inc.
Afton  Afton Generating Station
AFUDC Allowance for Funds Used During Construction
AMI Advanced Metering Infrastructure
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
ARPAlternative Revenue Program
ASU Accounting Standards Update
BACTAugust 2016 RD Best Available Control TechnologyRecommended Decision in PNM’s NM 2015 Rate Case issued by the Hearing Examiner on August 4, 2016
BART  Best Available Retrofit Technology
BDT Balanced Draft Technology
BHPBHP Billiton, Ltd
Board  Board of Directors of PNMR
BTMU MUFG Bank Ltd., formerly The Bank of Tokyo-Mitsubishi UFJ, Ltd.
BTMU Term Loan Agreement NM Capital’s $125.0 Million Unsecured Term Loan
BTUBritish Thermal Unit
CAA Clean Air Act
CCB  Coal Combustion ByproductByproducts
CCN Certificate of Convenience and Necessity
CIACContributions in Aid of Construction
CO2
  Carbon Dioxide
CSA Coal Supply Agreement
CTC  Competition Transition Charge
DC Circuit United States Court of Appeals for the District of Columbia Circuit
DOE  United States Department of Energy
DOI  United States Department of Interior
EGU Electric Generating Unit
EIS Environmental Impact Study
EPA  United States Environmental Protection Agency
ERCOT  Electric Reliability Council of Texas
ESA Endangered Species Act
Exchange Act Securities Exchange Act of 1934
Farmington The City of Farmington, New Mexico
FASB  Financial Accounting Standards Board
FERC  Federal Energy Regulatory Commission
FIP  Federal Implementation Plan
Four Corners  Four Corners Power Plant
Four Corners CSAFour Corners Power Plant Coal Supply Agreement
FPPAC  Fuel and Purchased Power Adjustment Clause
FTY Future Test Year
GAAP  Generally Accepted Accounting Principles in the United States of America
GHG  Greenhouse Gas Emissions

GWh  Gigawatt hours
IRP Integrated Resource Plan
IRS  Internal Revenue Service
ISFSI Independent Spent Fuel Storage Installation
KW  Kilowatt
KWh  Kilowatt Hour
La Luz  La Luz Generating Station

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
Los AlamosThe Incorporated County of Los Alamos, New Mexico
Luna  Luna Energy Facility
MD&A  Management’s Discussion and Analysis of Financial Condition and Results of Operations
MMBTU  Million BTUsBritish Thermal Units
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
NM 2015 Rate Case Request for a General Increase in Electric Rates Filed by PNM on August 27, 2015
NM 2016 Rate Case Request for a General Increase in Electric Rates Filed by PNM on December 7, 2016
NM Capital NM Capital Utility Corporation, an unregulated wholly-owned subsidiary of PNMR
NM District CourtUnited States District Court for the District of New Mexico
NM Supreme Court New Mexico Supreme Court
NMAG  New Mexico Attorney General
NMED  New Mexico Environment Department
NMIEC  New Mexico Industrial Energy Consumers Inc.
NMMMD The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department
NMPRC  New Mexico Public Regulation Commission
NMRDNM Renewable Development, LLC, owned 50% each by PNMR Development and AEP OnSite Partners, LLC
NO2
Nitrogen Dioxide
NOx  Nitrogen OxidesOxide
NOPR Notice of Proposed Rulemaking
NPDES National Pollutant Discharge Elimination System
NRC  United States Nuclear Regulatory Commission
NSPS  New Source Performance Standards
NSR  New Source Review
NTEC  Navajo Transitional Energy Company, LLC, an entity owned by the Navajo Nation
OCI  Other Comprehensive Income
OPEB  Other Post EmploymentPost-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 a wholly-owned subsidiary of PNMR
PNM 2016 Term Loan Agreement PNM’s $175.0 Million Unsecured Term Loan
PNM 2017 New Mexico Credit FacilityPNM’s $40.0 Million Unsecured Revolving Credit Facility
PNM 2017 Senior Unsecured Note Agreement PNM’s Agreement for the sale of Senior Unsecured Notes, aggregating $450.0 million
PNM 2017 Term Loan Agreement PNM’s $200.0 Million Unsecured Term Loan

PNM 2018 SUNs PNM’s Senior Unsecured Notes to be issued under the PNM 2017 Senior Unsecured Note Agreement
PNM New Mexico Credit FacilityPNM’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 Three-Year Unsecured Term Loan
PNMR 2016 One-Year Term Loan PNMR’s $100.0 Million One-Year Unsecured Term Loan
PNMR 2016 Two-Year Term Loan PNMR’s $100.0 Million Two-Year Unsecured Term Loan
PNMR 2018 SUNsPNMR’s $300.0 Million Aggregate Principal Amount of Senior Unsecured Notes due 2021
PNMR Development PNMR Development and Management Corporation,Company, an unregulated wholly-owned subsidiary of PNMR
PNMR Development Revolving Credit FacilityPNMR Development’s $24.5 Million Unsecured Revolving Credit Facility
PNMR Revolving Credit Facility PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PPA  Power Purchase Agreement
PSAPower Sales Agreement
PSD  Prevention of Significant Deterioration
PUCT  Public Utility Commission of Texas
PV  Photovoltaic
PVNGS  Palo Verde Nuclear Generating Station
RASan 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
RFP Request For Proposal
Rio Bravo Rio Bravo Generating Station
RMCRisk Management Committee
ROE Return on Equity
RPS  Renewable Energy Portfolio Standard
S&P  Standard and Poor’s Ratings Services
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
SJGS CSASan Juan Generating Station Coal Supply Agreement
SJGS RASan Juan Project Restructuring Agreement
SJPPASan Juan Project Participation Agreement
SNCR Selective Non-Catalytic Reduction

SO2
  Sulfur Dioxide
SOxSulfur Oxide
SPSSouthwestern Public Service Company
SRPSalt River Project
SUNsSenior Unsecured Notes
TECA  Texas Electric Choice Act
Tenth Circuit United States Court of Appeals for the Tenth Circuit
TNMP  Texas-New Mexico Power Company and Subsidiaries a wholly-owned subsidiary of TNP
TNMP 2017 Bond Purchase2018 Rate CaseTNMP’s General Rate Case Application Filed on May 30, 2018
TNMP 2018 Term Loan Agreement TNMP’s Agreement for the issuance of $60.0$20.0 Million First Mortgage BondsUnsecured Two-Year Term Loan

TNMP Revolving Credit Facility  TNMP’s $75.0 Million Secured Revolving Credit Facility
TNP  TNP Enterprises, Inc. and Subsidiaries a wholly-owned subsidiary of PNMR
Tri-State  Tri-State Generation and Transmission Association, Inc.
Tucson  Tucson Electric Power Company
UG-CSAUAMPS  Underground Coal Sales AgreementUtah Associated Municipal Power Systems
US Supreme Court United States Supreme Court of the United States
Valencia  Valencia Energy Facility
VaR  Value at Risk
VIE Variable Interest Entity
WACC  Weighted Average Cost of Capital
WEG WildEarth Guardians
Westmoreland Westmoreland Coal Company
Westmoreland Loan $125.0 Million of funding provided by NM Capital’s $125.0 million loanCapital to WSJ
WSJ Westmoreland San Juan, LLC, an indirect wholly-owned subsidiary of Westmoreland

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,Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 20162018 2017 2018 2017
(In thousands, except per share amounts)(In thousands, except per share amounts)
Electric Operating Revenues
$419,900
 $400,374
 $1,112,398
 $1,026,726
Electric Operating Revenues:
       
Contracts with customers$338,659
 $326,586
 $642,010
 $623,777
Alternative revenue programs5,660
 8,920
 6,584
 13,499
Other electric operating revenue7,994
 26,814
 21,597
 55,222
Total electric operating revenues352,313
 362,320
 670,191
 692,498
Operating Expenses:
   
 

   
 
Cost of energy103,748
 108,766
 310,818
 282,498
87,711
 104,267
 180,267
 207,070
Administrative and general46,268
 46,942
 138,923
 139,214
43,355
 42,984
 91,638
 88,379
Energy production costs31,970
 31,460
 98,150
 112,026
41,888
 34,393
 77,238
 66,180
Regulatory disallowances and restructuring costs—
 16,451
 —
 17,225
1,794
 —
 1,794
 —
Depreciation and amortization58,821
 53,017
 172,829
 153,801
60,063
 57,625
 118,785
 114,008
Transmission and distribution costs16,801
 16,056
 50,309
 49,965
18,450
 17,031
 35,406
 33,508
Taxes other than income taxes19,808
 19,611
 57,820
 57,598
19,723
 18,777
 39,602
 38,012
Total operating expenses277,416
 292,303
 828,849
 812,327
272,984
 275,077
 544,730
 547,157
Operating income142,484
 108,071
 283,549
 214,399
79,329
 87,243
 125,461
 145,341
Other Income and Deductions:              
Interest income3,582
 4,604
 12,348
 18,420
4,339
 3,885
 8,462
 8,766
Gains on available-for-sale securities5,406
 4,531
 17,730
 15,380
Gains (losses) on investment securities(1,670) 5,663
 (1,382) 12,324
Other income6,275
 4,884
 14,626
 13,413
4,796
 3,450
 8,265
 8,351
Other (deductions)(4,571) (3,764) (10,958) (10,866)(5,868) (5,042) (7,243) (10,663)
Net other income and deductions10,692
 10,255
 33,746
 36,347
1,597
 7,956
 8,102
 18,778
Interest Charges32,106
 32,467
 96,137
 97,179
33,321
 32,332
 66,376
 64,031
Earnings before Income Taxes121,070
 85,859
 221,158
 153,567
47,605
 62,867
 67,187
 100,088
Income Taxes42,743
 27,303
 75,154
 50,094
5,156
 21,636
 5,939
 32,411
Net Earnings78,327
 58,556
 146,004
 103,473
42,449
 41,231
 61,248
 67,677
(Earnings) Attributable to Valencia Non-controlling Interest(4,456) (4,006) (11,452) (11,037)(4,109) (3,544) (7,786) (6,996)
Preferred Stock Dividend Requirements of Subsidiary(132) (132) (396) (396)(132) (132) (264) (264)
Net Earnings Attributable to PNMR$73,739
 $54,418
 $134,156
 $92,040
$38,208
 $37,555
 $53,198
 $60,417
Net Earnings Attributable to PNMR per Common Share:              
Basic$0.92
 $0.68
 $1.68
 $1.15
$0.48
 $0.47
 $0.67
 $0.76
Diluted$0.92
 $0.68
 $1.67
 $1.15
$0.48
 $0.47
 $0.67
 $0.75
Dividends Declared per Common Share$0.2425
 $0.2200
 $0.7275
 $0.6600
$0.2650
 $0.2425
 $0.5300
 $0.4850

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



PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 20162018 2017 2018 2017
(In thousands)(In thousands)
Net Earnings$78,327
 $58,556
 $146,004
 $103,473
$42,449
 $41,231
 $61,248
 $67,677
Other Comprehensive Income (Loss):       
Other Comprehensive Income:       
Unrealized Gains on Available-for-Sale Securities:
              
Unrealized holding gains arising during the period, net of income tax (expense) of $(2,871), $(1,877), $(8,654), and $(1,216)4,528
 2,933
 13,648
 1,899
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,601, $1,985, $4,302, and $3,955(2,526) (3,101) (6,786) (6,180)
Unrealized holding gains arising during the period, net of income tax (expense) of $(91), $(2,777), $(374), and $(5,783)266
 4,378
 1,098
 9,120
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $126, $1,629, $794, and $2,701(371) (2,569) (2,332) (4,260)
Pension Liability Adjustment:              
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(626), $(537), $(1,878), and $(1,611)987
 839
 2,961
 2,517
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(482), $(626), $(962), and $(1,252)1,415
 987
 2,826
 1,974
Fair Value Adjustment for Cash Flow Hedges:              
Change in fair market value, net of income tax (expense) benefit of $(4), $(172), $108, and $5096
 269
 (170) (796)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(62), $(79), $(187), and $(224)99
 123
 297
 349
Total Other Comprehensive Income (Loss)3,094
 1,063
 9,950
 (2,211)
Change in fair market value, net of income tax (expense) benefit of $(143), $40, $(615), and $112419
 (63) 1,805
 (176)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(12), $(82), $1, and $(125)34
 130
 (6) 198
Total Other Comprehensive Income1,763
 2,863
 3,391
 6,856
Comprehensive Income81,421
 59,619
 155,954
 101,262
44,212
 44,094
 64,639
 74,533
Comprehensive (Income) Attributable to Valencia Non-controlling Interest(4,456) (4,006) (11,452) (11,037)(4,109) (3,544) (7,786) (6,996)
Preferred Stock Dividend Requirements of Subsidiary(132) (132) (396) (396)(132) (132) (264) (264)
Comprehensive Income Attributable to PNMR$76,833
 $55,481
 $144,106
 $89,829
$39,971
 $40,418
 $56,589
 $67,273

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



PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,Six Months Ended June 30,
2017 20162018 2017
(In thousands)(In thousands)
Cash Flows From Operating Activities:      
Net earnings$146,004
 $103,473
$61,248
 $67,677
Adjustments to reconcile net earnings to net cash flows from operating activities:      
Depreciation and amortization200,286
 178,137
137,020
 131,861
Deferred income tax expense75,224
 50,302
5,888
 32,443
Net unrealized (gains) losses on commodity derivatives968
 2,179
(56) 939
Realized (gains) on available-for-sale securities(17,730) (15,380)
(Gains) losses on investment securities1,382
 (12,324)
Stock based compensation expense5,322
 4,401
3,325
 4,561
Regulatory disallowances and restructuring costs—
 17,225
1,794
 —
Allowance for equity funds used during construction(6,217) (3,058)(4,641) (3,465)
Other, net1,409
 2,104
1,595
 1,056
Changes in certain assets and liabilities:      
Accounts receivable and unbilled revenues(21,077) (1,145)(17,130) (12,204)
Materials, supplies, and fuel stock(203) (4,629)(8,282) 969
Other current assets22,761
 (11,819)(16,130) 1,613
Other assets(5,981) 1,916
2,603
 3,186
Accounts payable3,729
 6,192
(21,229) (2,052)
Accrued interest and taxes20,722
 20,816
(4,865) (6,802)
Other current liabilities(1,588) (19,431)(1,516) (2,498)
Other liabilities(6,292) (10,297)(7,106) (4,341)
Net cash flows from operating activities417,337
 320,986
133,900
 200,619
      
Cash Flows From Investing Activities:      
Additions to utility and non-utility plant(353,423) (502,530)(245,587) (230,882)
Proceeds from sales of available-for-sale securities456,577
 280,989
Purchases of available-for-sale securities(461,126) (284,706)
Return of principal on PVNGS lessor notes—
 8,547
Investment in Westmoreland Loan—
 (122,250)
Proceeds from sales of investment securities794,088
 358,045
Purchases of investment securities(797,271) (359,853)
Principal repayments on Westmoreland Loan28,770
 15,000
56,640
 19,180
Investments in NMRD(8,000) —
Other, net160
 179
(120) 143
Net cash flows from investing activities(329,042) (604,771)(200,250) (213,367)

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


PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended September 30,Six Months Ended June 30,
2017 20162018 2017
(In thousands)(In thousands)
Cash Flows From Financing Activities:      
Revolving credit facilities borrowings (repayments), net(20,600) 105,300
(22,800) 86,400
Long-term borrowings317,000
 503,500
709,652
 57,000
Repayment of long-term debt(263,323) (288,157)(550,137) (77,447)
Proceeds from stock option exercise1,739
 6,668
924
 1,574
Awards of common stock(13,816) (14,920)(12,268) (13,166)
Dividends paid(58,344) (52,967)(42,480) (38,896)
Valencia’s transactions with its owner(12,963) (12,327)(8,381) (7,731)
Amounts received under transmission interconnection arrangements11,879
 3,262
—
 11,419
Refunds paid under transmission interconnection arrangements(9,368) (2,246)(1,661) (8,783)
Other, net(1,872) (2,698)
Debt issuance costs and other, net(5,584) (951)
Net cash flows from financing activities(49,668) 245,415
67,265
 9,419
      
Change in Cash and Cash Equivalents38,627
 (38,370)
Cash and Cash Equivalents at Beginning of Period4,522
 46,051
Cash and Cash Equivalents at End of Period$43,149
 $7,681
Change in Cash, Restricted Cash, and Equivalents915
 (3,329)
Cash, Restricted Cash, and Equivalents at Beginning of Period3,974
 5,522
Cash, Restricted Cash, and Equivalents at End of Period$4,889
 $2,193
   
Restricted Cash Included in Other Current Assets on Condensed Consolidated Balance Sheets:   
At beginning of period$—
 $1,000
At end of period$—
 $—
      
Supplemental Cash Flow Disclosures:      
Interest paid, net of amounts capitalized$75,356
 $75,537
$59,626
 $59,982
Income taxes paid (refunded), net$625
 $850
$842
 $625
      
Supplemental schedule of noncash investing activities:      
(Increase) decrease in accrued plant additions$(4,499) $30,208
$17,303
 $1,279

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



PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
2017		 December 31,
2016		June 30,
2018		 December 31,
2017
(In thousands)(In thousands)
ASSETS      
Current Assets:      
Cash and cash equivalents$43,149
 $4,522
$4,889
 $3,974
Accounts receivable, net of allowance for uncollectible accounts of $1,063 and $1,209107,428
 87,012
Accounts receivable, net of allowance for uncollectible accounts of $1,189 and $1,08189,158
 90,473
Unbilled revenues57,241
 58,284
70,904
 54,055
Other receivables16,567
 28,245
24,338
 17,582
Current portion of Westmoreland Loan12,272
 38,360
—
 3,576
Materials, supplies, and fuel stock68,179
 73,027
74,785
 66,502
Regulatory assets3,424
 3,855
6,586
 2,933
Commodity derivative instruments3,093
 5,224
1,094
 1,088
Income taxes receivable6,761
 6,066
7,670
 6,879
Other current assets56,421
 73,444
51,818
 47,358
Total current assets374,535
 378,039
331,242
 294,420
Other Property and Investments:      
Long-term portion of Westmoreland Loan53,958
 56,640
—
 53,064
Available-for-sale securities306,444
 272,977
Investment securities323,105
 323,524
Equity investment in NMRD24,761
 16,510
Other investments386
 547
373
 503
Non-utility property3,404
 3,404
3,404
 3,404
Total other property and investments364,192
 333,568
351,643
 397,005
Utility Plant:      
Plant in service, held for future use, and to be abandoned7,133,646
 6,944,534
Plant in service and held for future use7,438,356
 7,238,285
Less accumulated depreciation and amortization2,431,695
 2,334,938
2,648,684
 2,592,692
4,701,951
 4,609,596
4,789,672
 4,645,593
Construction work in progress301,466
 208,206
220,065
 245,933
Nuclear fuel, net of accumulated amortization of $49,895 and $43,90588,702
 86,913
Nuclear fuel, net of accumulated amortization of $43,309 and $43,52490,962
 88,701
Net utility plant5,092,119
 4,904,715
5,100,699
 4,980,227
Deferred Charges and Other Assets:      
Regulatory assets489,416
 501,223
588,971
 600,672
Goodwill278,297
 278,297
278,297
 278,297
Commodity derivative instruments3,846
 —
3,014
 3,556
Other deferred charges94,849
 75,238
96,223
 91,926
Total deferred charges and other assets866,408
 854,758
966,505
 974,451
$6,697,254
 $6,471,080
$6,750,089
 $6,646,103

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



PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
2017		 December 31,
2016		June 30,
2018		 December 31,
2017
(In thousands, except share information)(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY      
Current Liabilities:      
Short-term debt$266,500
 $287,100
$282,600
 $305,400
Current installments of long-term debt165,312
 273,348
471,690
 256,895
Accounts payable89,882
 86,705
82,851
 121,383
Customer deposits10,951
 11,374
10,919
 11,028
Accrued interest and taxes83,288
 61,871
58,283
 62,357
Regulatory liabilities7,156
 3,609
—
 2,309
Commodity derivative instruments1,279
 2,339
1,416
 1,182
Dividends declared19,448
 19,448
132
 21,240
Other current liabilities67,069
 59,314
54,259
 53,850
Total current liabilities710,885
 805,108
962,150
 835,644
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs2,282,390
 2,119,364
2,122,352
 2,180,750
Deferred Credits and Other Liabilities:      
Accumulated deferred income taxes1,015,967
 940,650
566,084
 547,210
Regulatory liabilities456,740
 455,649
928,706
 933,578
Asset retirement obligations133,841
 127,519
152,300
 146,679
Accrued pension liability and postretirement benefit cost116,812
 125,844
84,934
 94,003
Commodity derivative instruments3,846
 —
3,014
 3,556
Other deferred credits132,098
 140,545
130,705
 131,706
Total deferred credits and other liabilities1,859,304
 1,790,207
1,865,743
 1,856,732
Total liabilities4,852,579
 4,714,679
4,950,245
 4,873,126
Commitments and Contingencies (See Note 11)

 

Commitments and Contingencies (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
11,529
 11,529
Equity:      
PNMR common stockholders’ equity:   
PNMR common stockholders' equity:   
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)1,156,906
 1,163,661
1,149,646
 1,157,665
Accumulated other comprehensive income (loss), net of income taxes(82,501) (92,451)(103,757) (95,940)
Retained earnings691,332
 604,742
676,826
 633,528
Total PNMR common stockholders’ equity1,765,737
 1,675,952
1,722,715
 1,695,253
Non-controlling interest in Valencia67,409
 68,920
65,600
 66,195
Total equity1,833,146
 1,744,872
1,788,315
 1,761,448
$6,697,254
 $6,471,080
$6,750,089
 $6,646,103
      

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


PNM RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)

Attributable to PNMR 
Non-
controlling
Interest
in Valencia
  Attributable to PNMR 
Non-
controlling
Interest
in Valencia
  
Common
Stock
 AOCI 
Retained
Earnings
 Total PNMR Common Stockholders’ Equity 
Total
Equity
Common
Stock
 AOCI 
Retained
Earnings
 Total PNMR Common Stockholders’ Equity 
Total
Equity
(In thousands)(In thousands)
Balance at December 31, 2016, as originally reported$1,163,661
 $(92,451) $604,742
 $1,675,952
 $68,920
 $1,744,872
Cumulative effect adjustment (Note 8)—
 —
 10,382
 10,382
 —
 10,382
Balance at January 1, 2017, as adjusted1,163,661
 (92,451) 615,124
 1,686,334
 68,920
 1,755,254
Balance at December 31, 2017, as originally reported$1,157,665
 $(95,940) $633,528
 $1,695,253
 $66,195
 $1,761,448
Cumulative effect adjustment (Note 7)—
 (11,208) 11,208
 —
 —
 —
Balance at January 1, 2018, as adjusted1,157,665
 (107,148) 644,736
 1,695,253
 66,195
 1,761,448
Net earnings before subsidiary preferred stock dividends—
 —
 134,552
 134,552
 11,452
 146,004
—
 —
 53,462
 53,462
 7,786
 61,248
Total other comprehensive income—
 9,950
 —
 9,950
 —
 9,950
—
 3,391
 —
 3,391
 —
 3,391
Subsidiary preferred stock dividends—
 —
 (396) (396) —
 (396)—
 —
 (264) (264) —
 (264)
Dividends declared on common stock—
 —
 (57,948) (57,948) —
 (57,948)—
 —
 (21,108) (21,108) —
 (21,108)
Proceeds from stock option exercise1,739
 —
 —
 1,739
 —
 1,739
924
 —
 —
 924
 —
 924
Awards of common stock(13,816) —
 —
 (13,816) —
 (13,816)(12,268) —
 —
 (12,268) —
 (12,268)
Stock based compensation expense5,322
 —
 —
 5,322
 —
 5,322
3,325
 —
 —
 3,325
 —
 3,325
Valencia’s transactions with its owner—
 —
 —
 —
 (12,963) (12,963)—
 —
 —
 —
 (8,381) (8,381)
Balance at September 30, 2017$1,156,906
 $(82,501) $691,332
 $1,765,737
 $67,409
 $1,833,146
Balance at June 30, 2018$1,149,646
 $(103,757) $676,826
 $1,722,715
 $65,600
 $1,788,315


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



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,Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 20162018 2017 2018 2017
(In thousands)(In thousands)
Electric Operating Revenues$327,254
 $311,276
 $854,909
 $780,228
Electric Operating Revenues:
       
Contracts with customers$254,728
 $246,402
 $477,291
 $468,465
Alternative revenue programs1,789
 2,881
 1,854
 3,968
Other electric operating revenue7,994
 26,814
 21,597
 55,222
Total electric operating revenues264,511
 276,097
 500,742
 527,655
Operating Expenses:              
Cost of energy82,367
 88,565
 246,635
 222,376
66,361
 82,952
 137,163
 164,268
Administrative and general42,026
 41,370
 127,012
 122,553
40,922
 39,798
 84,648
 80,708
Energy production costs31,970
 31,460
 98,150
 112,026
41,888
 34,393
 77,238
 66,180
Regulatory disallowances and restructuring costs—
 16,451
 —
 17,225
1,794
 —
 1,794
 —
Depreciation and amortization36,764
 33,312
 109,228
 97,778
38,213
 36,448
 74,840
 72,464
Transmission and distribution costs10,207
 9,311
 30,301
 29,868
10,993
 10,175
 20,820
 20,094
Taxes other than income taxes10,668
 10,750
 32,837
 33,289
11,461
 11,029
 23,069
 22,169
Total operating expenses214,002
 231,219
 644,163
 635,115
211,632
 214,795
 419,572
 425,883
Operating income113,252
 80,057
 210,746
 145,113
52,879
 61,302
 81,170
 101,772
Other Income and Deductions:              
Interest income1,782
 1,509
 6,457
 8,549
3,381
 1,858
 5,868
 4,675
Gains on available-for-sale securities5,406
 4,531
 17,730
 15,380
Gains (losses) on investment securities(1,670) 5,663
 (1,382) 12,324
Other income3,762
 3,239
 10,270
 9,578
2,292
 2,665
 4,684
 6,508
Other (deductions)(2,826) (2,790) (8,076) (7,653)(3,768) (4,566) (5,229) (9,526)
Net other income and deductions8,124
 6,489
 26,381
 25,854
235
 5,620
 3,941
 13,981
Interest Charges20,451
 22,213
 62,393
 66,494
19,988
 20,931
 40,818
 41,943
Earnings before Income Taxes100,925
 64,333
 174,734
 104,473
33,126
 45,991
 44,293
 73,810
Income Taxes35,642
 19,343
 58,865
 32,131
2,345
 15,515
 1,997
 23,223
Net Earnings65,283
 44,990
 115,869
 72,342
30,781
 30,476
 42,296
 50,587
(Earnings) Attributable to Valencia Non-controlling Interest(4,456) (4,006) (11,452) (11,037)(4,109) (3,544) (7,786) (6,996)
Net Earnings Attributable to PNM60,827
 40,984
 104,417
 61,305
26,672
 26,932
 34,510
 43,591
Preferred Stock Dividends Requirements(132) (132) (396) (396)(132) (132) (264) (264)
Net Earnings Available for PNM Common Stock$60,695
 $40,852
 $104,021
 $60,909
$26,540
 $26,800
 $34,246
 $43,327

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


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,Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 20162018 2017 2018 2017
(In thousands)(In thousands)
Net Earnings$65,283
 $44,990
 $115,869
 $72,342
$30,781
 $30,476
 $42,296
 $50,587
Other Comprehensive Income (Loss):       
Other Comprehensive Income:       
Unrealized Gains on Available-for-Sale Securities:
              
Unrealized holding gains arising during the period, net of income tax (expense) of $(2,871), $(1,877), $(8,654), and $(1,216)4,528
 2,933
 13,648
 1,899
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,601, $1,985, $4,302, and $3,955(2,526) (3,101) (6,786) (6,180)
Unrealized holding gains arising during the period, net of income tax (expense) of $(91), $(2,777), $(374), and $(5,783)266
 4,378
 1,098
 9,120
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $126, $1,629, $794, and $2,701(371) (2,569) (2,332) (4,260)
Pension Liability Adjustment:              
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(626), $(537), $(1,878), and $(1,611)987
 839
 2,961
 2,517
Total Other Comprehensive Income (Loss)2,989
 671
 9,823
 (1,764)
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(482), $(626), $(962), and $(1,252)1,415
 987
 2,826
 1,974
Total Other Comprehensive Income1,310
 2,796
 1,592
 6,834
Comprehensive Income68,272
 45,661
 125,692
 70,578
32,091
 33,272
 43,888
 57,421
Comprehensive (Income) Attributable to Valencia Non-controlling Interest(4,456) (4,006) (11,452) (11,037)(4,109) (3,544) (7,786) (6,996)
Comprehensive Income Attributable to PNM$63,816
 $41,655
 $114,240
 $59,541
$27,982
 $29,728
 $36,102
 $50,425

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



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,Six Months Ended June 30,
2017 20162018 2017
(In thousands)(In thousands)
Cash Flows From Operating Activities:      
Net earnings$115,869
 $72,342
$42,296
 $50,587
Adjustments to reconcile net earnings to net cash flows from operating activities:      
Depreciation and amortization134,541
 122,344
90,713
 88,864
Deferred income tax expense59,866
 33,175
2,342
 23,685
Net unrealized (gains) losses on commodity derivatives968
 2,179
(56) 939
Realized (gains) on available-for-sale securities(17,730) (15,380)
(Gains) losses on investment securities1,382
 (12,324)
Regulatory disallowances and restructuring costs—
 17,225
1,794
 —
Allowance for equity funds used during construction(5,908) (2,654)(3,879) (3,331)
Other, net1,705
 2,091
1,595
 1,053
Changes in certain assets and liabilities:      
Accounts receivable and unbilled revenues(13,881) 8,283
(12,057) (8,846)
Materials, supplies, and fuel stock1,385
 (7,731)(7,071) 1,591
Other current assets24,488
 (4,005)(17,995) 4,623
Other assets6,925
 10,117
8,296
 8,539
Accounts payable123
 6,819
(13,050) (754)
Accrued interest and taxes16,221
 16,146
(988) (1,520)
Other current liabilities(17,988) (18,908)(11,364) 9,220
Other liabilities(8,792) (13,401)(10,300) (6,949)
Net cash flows from operating activities297,792
 228,642
71,658
 155,377
      
Cash Flows From Investing Activities:      
Utility plant additions(206,499) (377,637)(120,287) (125,698)
Proceeds from sales of available-for-sale securities456,577
 280,989
Purchases of available-for-sale securities(461,126) (284,706)
Return of principal on PVNGS lessor notes—
 8,547
Proceeds from sales of investment securities794,088
 358,045
Purchases of investment securities(797,271) (359,853)
Other, net150
 171
131
 143
Net cash flows from investing activities(210,898) (372,636)(123,339) (127,363)

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



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,Six Months Ended June 30,
2017 20162018 2017
(In thousands)(In thousands)
Cash Flows From Financing Activities:      
Revolving credit facilities borrowings (repayments), net(61,000) 42,400
(6,200) (23,000)
Short-term borrowings (repayments) - affiliate, net4,900
 —
Long-term borrowings257,000
 321,000
350,000
 57,000
Repayment of long-term debt(232,000) (271,000)(350,000) (57,000)
Equity contribution from parent—
 28,142
Dividends paid(396) (4,538)(264) (264)
Valencia’s transactions with its owner(12,963) (12,327)(8,381) (7,731)
Amounts received under transmission interconnection arrangements11,879
 3,262
68,200
 11,419
Refunds paid under transmission interconnection arrangements(9,368) (2,246)(1,661) (8,783)
Other, net(1,000) (1,944)
Debt issuance costs and other, net(3,147) (953)
Net cash flows from financing activities(47,848) 102,749
53,447
 (29,312)
      
Change in Cash and Cash Equivalents39,046
 (41,245)
Cash and Cash Equivalents at Beginning of Period324
 43,138
Cash and Cash Equivalents at End of Period$39,370
 $1,893
Change in Cash, Restricted Cash, and Equivalents1,766
 (1,298)
Cash, Restricted Cash, and Equivalents at Beginning of Period1,108
 1,324
Cash, Restricted Cash, and Equivalents at End of Period$2,874
 $26
   
Restricted Cash Included in Other Current Assets on Condensed Consolidated Balance Sheets:   
At beginning of period$—
 $1,000
At end of period$—
 $—
      
Supplemental Cash Flow Disclosures:      
Interest paid, net of amounts capitalized$48,627
 $53,791
$39,881
 $39,584
Income taxes paid (refunded), net$—
 $—
$—
 $—
      
Supplemental schedule of noncash investing activities:      
(Increase) decrease in accrued plant additions$(9,399) $20,200
$(841) $(5,392)

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



PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
2017		 December 31,
2016		June 30,
2018		 December 31,
2017
(In thousands)(In thousands)
ASSETS      
Current Assets:      
Cash and cash equivalents$39,370
 $324
$2,874
 $1,108
Accounts receivable, net of allowance for uncollectible accounts of $1,063 and $1,20979,668
 65,003
Accounts receivable, net of allowance for uncollectible accounts of $1,189 and $1,08162,677
 67,227
Unbilled revenues45,800
 48,289
58,880
 43,869
Other receivables13,510
 25,514
22,680
 14,541
Affiliate receivables8,944
 8,886
9,037
 9,486
Materials, supplies, and fuel stock63,016
 64,401
67,930
 60,859
Regulatory assets2,526
 3,442
5,815
 2,139
Commodity derivative instruments3,093
 5,224
1,094
 1,088
Income taxes receivable26,808
 25,807
3,754
 3,410
Other current assets48,883
 67,355
46,369
 39,904
Total current assets331,618
 314,245
281,110
 243,631
Other Property and Investments:      
Available-for-sale securities306,444
 272,977
Investment securities323,105
 323,524
Other investments166
 316
153
 283
Non-utility property96
 96
96
 96
Total other property and investments306,706
 273,389
323,354
 323,903
Utility Plant:      
Plant in service, held for future use, and to be abandoned5,463,764
 5,359,211
Plant in service and held for future use5,672,141
 5,501,070
Less accumulated depreciation and amortization1,881,371
 1,809,528
2,064,741
 2,029,534
3,582,393
 3,549,683
3,607,400
 3,471,536
Construction work in progress223,677
 158,122
114,535
 204,079
Nuclear fuel, net of accumulated amortization of $49,895 and $43,90588,702
 86,913
Nuclear fuel, net of accumulated amortization of $43,309 and $43,52490,962
 88,701
Net utility plant3,894,772
 3,794,718
3,812,897
 3,764,316
Deferred Charges and Other Assets:      
Regulatory assets349,453
 365,413
447,691
 459,239
Goodwill51,632
 51,632
51,632
 51,632
Commodity derivative instruments3,846
 —
3,014
 3,556
Other deferred charges85,789
 68,149
74,579
 75,286
Total deferred charges and other assets490,720
 485,194
576,916
 589,713
$5,023,816
 $4,867,546
$4,994,277
 $4,921,563
      

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



PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
2017		 December 31,
2016		June 30,
2018		 December 31,
2017
(In thousands, except share information)(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY      
Current Liabilities:      
Short-term debt$—
 $61,000
$33,600
 $39,800
Short-term debt - affiliate4,900
 —
Current installments of long-term debt—
 231,880
200,012
 23
Accounts payable65,088
 55,566
64,885
 77,094
Affiliate payables9,738
 23,183
8,186
 22,875
Customer deposits10,951
 11,374
10,919
 11,028
Accrued interest and taxes52,041
 34,819
33,301
 33,945
Regulatory liabilities7,138
 3,517
—
 784
Commodity derivative instruments1,279
 2,339
1,416
 1,182
Dividends declared132
 132
132
 132
Transmission interconnection arrangement liabilities12,167
 522
Other current liabilities32,532
 33,029
34,910
 31,633
Total current liabilities191,066
 457,361
392,261
 218,496
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs1,657,396
 1,399,489
1,455,748
 1,657,887
Deferred Credits and Other Liabilities:      
Accumulated deferred income taxes810,995
 748,666
463,895
 449,012
Regulatory liabilities423,477
 423,701
742,574
 754,441
Asset retirement obligations132,878
 126,601
151,289
 145,707
Accrued pension liability and postretirement benefit cost106,742
 114,427
78,184
 86,124
Commodity derivative instruments3,846
 —
3,014
 3,556
Other deferred credits106,762
 118,980
172,171
 106,442
Total deferred credits and liabilities1,584,700
 1,532,375
1,611,127
 1,545,282
Total liabilities3,433,162
 3,389,225
3,459,136
 3,421,665
Commitments and Contingencies (See Note 11)

 

Commitments and Contingencies (Note 11)

 

Cumulative Preferred Stock      
without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)11,529
 11,529
11,529
 11,529
Equity:      
PNM common stockholder’s equity:      
Common stock (no par value; 40,000,000 shares authorized; issued and outstanding 39,117,799 shares)1,264,918
 1,264,918
1,264,918
 1,264,918
Accumulated other comprehensive income (loss), net of income taxes(82,605) (92,428)(106,709) (97,093)
Retained earnings329,403
 225,382
299,803
 254,349
Total PNM common stockholder’s equity1,511,716
 1,397,872
1,458,012
 1,422,174
Non-controlling interest in Valencia67,409
 68,920
65,600
 66,195
Total equity1,579,125
 1,466,792
1,523,612
 1,488,369
$5,023,816
 $4,867,546
$4,994,277
 $4,921,563

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

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    Attributable to PNM    
    
Total PNM
Common
Stockholder’s
Equity
 
Non-
controlling
 Interest in Valencia
      
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
 
Total PNM
Common
Stockholder’s
Equity
Non-
controlling
 Interest in Valencia
 
Total PNM
Common
Stockholder’s
Equity
Non-
controlling
 Interest in Valencia
(In thousands)(In thousands)
Balance at December 31, 2016$1,264,918
 $(92,428) $225,382
 $1,397,872
$68,920
$1,466,792
Balance at December 31, 2017, as originally reported$1,264,918
 $(97,093) $254,349
 $1,422,174
$66,195
$1,488,369
Cumulative effect adjustment (Note 7)—
 (11,208) 11,208
 —
 —
 —
Balance at January 1, 2018, as adjusted1,264,918
 (108,301) 265,557
 1,422,174
 66,195
 1,488,369
Net earnings—
 —
 104,417
 104,417
 11,452
 115,869
—
 —
 34,510
 34,510
 7,786
 42,296
Total other comprehensive income—
 9,823
 —
 9,823
 —
 9,823
—
 1,592
 —
 1,592
 —
 1,592
Dividends declared on preferred stock—
 —
 (396) (396) —
 (396)—
 —
 (264) (264) —
 (264)
Valencia’s transactions with its owner—
 —
 —
 —
 (12,963) (12,963)—
 —
 —
 —
 (8,381) (8,381)
Balance at September 30, 2017$1,264,918
 $(82,605) $329,403
 $1,511,716
 $67,409
 $1,579,125
Balance at June 30, 2018$1,264,918
 $(106,709) $299,803
 $1,458,012
 $65,600
 $1,523,612


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

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,Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 20162018 2017 2018 2017
(In thousands)(In thousands)
Electric Operating Revenues$92,646
 $89,098
 $257,489
 $246,498
Electric Operating Revenues:
       
Contracts with customers$83,931
 $80,184
 $164,719
 $155,312
Alternative revenue programs3,871
 6,039
 4,730
 9,531
Total Electric Operating Revenues
87,802
 86,223
 169,449
 164,843
Operating Expenses:              
Cost of energy21,381
 20,201
 64,183
 60,122
21,350
 21,315
 43,104
 42,802
Administrative and general10,765
 9,588
 30,402
 29,382
8,852
 9,235
 19,561
 19,638
Depreciation and amortization16,424
 16,354
 47,392
 45,760
16,113
 15,597
 32,500
 30,968
Transmission and distribution costs6,594
 6,745
 20,008
 20,097
7,457
 6,856
 14,586
 13,414
Taxes other than income taxes8,008
 7,851
 21,778
 20,849
7,201
 6,934
 14,337
 13,770
Total operating expenses63,172
 60,739
 183,763
 176,210
60,973
 59,937
 124,088
 120,592
Operating income29,474
 28,359
 73,726
 70,288
26,829
 26,286
 45,361
 44,251
Other Income and Deductions:              
Other income2,258
 1,376
 3,621
 2,999
2,223
 541
 2,976
 1,363
Other (deductions)(1,030) (521) (1,229) (860)(1,391) (109) (1,060) (198)
Net other income and deductions1,228
 855
 2,392
 2,139
832
 432
 1,916
 1,165
Interest Charges7,704
 7,308
 22,619
 22,150
7,801
 7,510
 15,530
 14,915
Earnings before Income Taxes22,998
 21,906
 53,499
 50,277
19,860
 19,208
 31,747
 30,501
Income Taxes8,271
 8,053
 18,964
 18,460
4,493
 7,004
 6,968
 10,693
Net Earnings$14,727
 $13,853
 $34,535
 $31,817
$15,367
 $12,204
 $24,779
 $19,808

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




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,Six Months Ended June 30,
2017 20162018 2017
(In thousands)(In thousands)
Cash Flows From Operating Activities:      
Net earnings$34,535
 $31,817
$24,779
 $19,808
Adjustments to reconcile net earnings to net cash flows from operating activities:      
Depreciation and amortization48,754
 47,055
33,390
 31,877
Deferred income tax expense8,578
 (739)
Allowance for equity funds used during construction(309) (405)
Other, net(296) 14
Deferred income tax expense (benefit)(900) 4,894
Allowance for equity funds used during construction and other, net(762) (130)
Changes in certain assets and liabilities:      
Accounts receivable and unbilled revenues(7,196) (9,428)(5,073) (3,358)
Materials and supplies(1,588) 3,102
(1,211) (622)
Other current assets(1,674) (3,570)(378) (3,897)
Other assets(13,799) (8,415)(5,603) (5,747)
Accounts payable669
 (6,758)(4,161) 138
Accrued interest and taxes13,550
 22,896
1,610
 (308)
Other current liabilities945
 (363)5,410
 1,957
Other liabilities1,633
 399
3,874
 717
Net cash flows from operating activities83,802
 75,605
50,975
 45,329
Cash Flows From Investing Activities:      
Utility plant additions(106,914) (93,048)(115,361) (78,940)
Net cash flows from investing activities(106,914) (93,048)(115,361) (78,940)
Cash Flow From Financing Activities:      
Revolving credit facilities borrowings (repayments), net—
 (59,000)13,500
 47,000
Short-term borrowings (repayments) – affiliate, net(4,600) (11,800)100
 3,400
Long-term borrowings60,000
 60,000
60,000
 —
Equity contribution from parent—
 50,000
Dividends paid(29,663) (17,965)(10,436) (17,459)
Other, net(874) (775)
Debt issuance costs and other, net(478) —
Net cash flows from financing activities24,863
 20,460
62,686
 32,941
      
Change in Cash and Cash Equivalents1,751
 3,017
(1,700) (670)
Cash and Cash Equivalents at Beginning of Period671
 11,700
 671
Cash and Cash Equivalents at End of Period$2,422
 $3,018
$—
 $1
      
Supplemental Cash Flow Disclosures:      
Interest paid, net of amounts capitalized$16,721
 $15,642
$13,085
 $13,999
Income taxes paid (refunded), net$750
 $850
$842
 $750
      
Supplemental schedule of noncash investing activities:      
(Increase) decrease in accrued plant additions$(251) $(10)$14,886
 $1,700

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




TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
2017		 December 31,
2016		June 30,
2018		 December 31,
2017
(In thousands)(In thousands)
ASSETS      
Current Assets:      
Cash and cash equivalents$2,422
 $671
$—
 $1,700
Accounts receivable27,760
 22,009
26,481
 23,246
Unbilled revenues11,441
 9,995
12,024
 10,186
Other receivables2,698
 2,090
2,639
 2,860
Affiliate receivables—
 336
Materials and supplies5,163
 8,626
6,855
 5,643
Regulatory assets898
 413
771
 794
Other current assets1,609
 1,031
1,752
 1,131
Total current assets51,991
 44,835
50,522
 45,896
Other Property and Investments:      
Other investments220
 231
220
 220
Non-utility property2,240
 2,240
2,240
 2,240
Total other property and investments2,460
 2,471
2,460
 2,460
Utility Plant:      
Plant in service and plant held for future use1,433,901
 1,380,584
1,531,459
 1,504,778
Less accumulated depreciation and amortization449,476
 429,397
470,741
 460,858
984,425
 951,187
1,060,718
 1,043,920
Construction work in progress53,545
 16,978
94,810
 34,350
Net utility plant1,037,970
 968,165
1,155,528
 1,078,270
Deferred Charges and Other Assets:      
Regulatory assets139,963
 135,810
141,280
 141,433
Goodwill226,665
 226,665
226,665
 226,665
Other deferred charges6,170
 5,277
6,856
 6,046
Total deferred charges and other assets372,798
 367,752
374,801
 374,144
$1,465,219
 $1,383,223
$1,583,311
 $1,500,770

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


TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY-OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
2017		 December 31,
2016		June 30,
2018		 December 31,
2017
(In thousands, except share information)(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY      
Current Liabilities:      
Short-term debt$13,500
 $—
Short-term debt – affiliate$—
 $4,600
100
 —
Current installments of long-term debt171,683
 —
Accounts payable12,578
 16,709
10,766
 29,812
Affiliate payables3,736
 3,793
6,112
 667
Accrued interest and taxes59,131
 45,581
31,229
 29,619
Regulatory liabilities18
 92
—
 1,525
Other current liabilities3,210
 2,134
3,604
 2,450
Total current liabilities78,673
 72,909
236,994
 64,073
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs480,589
 420,875
368,644
 480,620
Deferred Credits and Other Liabilities:      
Accumulated deferred income taxes254,525
 245,785
125,623
 126,415
Regulatory liabilities33,263
 31,948
186,132
 179,137
Asset retirement obligations789
 754
826
 793
Accrued pension liability and postretirement benefit cost10,070
 11,417
6,750
 7,879
Other deferred credits9,203
 6,300
9,594
 7,448
Total deferred credits and other liabilities307,850
 296,204
328,925
 321,672
Total liabilities867,112
 789,988
934,563
 866,365
Commitments and Contingencies (See Note 11)

 

Common Stockholder’s Equity:   
Commitments and Contingencies (Note 11)

 

Common Stockholder's Equity:   
Common stock ($10 par value; 12,000,000 shares authorized; issued and outstanding 6,358 shares)64
 64
64
 64
Paid-in-capital454,166
 454,166
504,166
 504,166
Retained earnings143,877
 139,005
144,518
 130,175
Total common stockholder’s equity598,107
 593,235
648,748
 634,405
$1,465,219
 $1,383,223
$1,583,311
 $1,500,770

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


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 EquityCommon Stock Paid-in Capital Retained Earnings Total Common Stockholder’s Equity
(In thousands)(In thousands)
Balance at December 31, 2016$64
 $454,166
 $139,005
 $593,235
Balance at December 31, 2017$64
 $504,166
 $130,175
 $634,405
Net earnings—
 —
 34,535
 34,535
—
 —
 24,779
 24,779
Dividends declared on common stock—
 —
 (29,663) (29,663)—
 —
 (10,436) (10,436)
Balance at September 30, 2017$64
 $454,166
 $143,877
 $598,107
Balance at June 30, 2018$64
 $504,166
 $144,518
 $648,748

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



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 SeptemberJune 30, 20172018 and December 31, 20162017, the consolidated results of operations and comprehensive income for the three and ninesix months ended SeptemberJune 30, 2018 and 2017, and 2016, and the consolidated cash flows for the ninesix months ended SeptemberJune 30, 20172018 and 2016.2017. 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 20162017 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 20172018 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual audited 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 20162017 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 Valencia (Note 5) and, through January 15, 2016, the PVNGS Capital Trust.6). 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.

Certain PNMR shared services’ expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions.transactions, and interconnection billings (Note 15). All intercompany transactions and balances have been eliminated. See Note 14.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by the 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 bebeing 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 $0.2650 per share in July 2018 and $0.2425 in

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)


declared dividends on common stock considered to be for the second quarter of $0.2425 per share in July 2017, and $0.22 in July 2016, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. The Board declared dividends on common stock considered to be for the third quarter of $0.2425 per share in September 2017 and $0.22 per share in September 2016, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statement of Earnings.

TNMP declared and paid cash dividends on common stock to PNMR of $29.7$10.4 million and $17.5 million in the ninesix months ended SeptemberJune 30, 2018 and 2017. PNM andIn July 2018, TNMP declared and paid a cash dividends on common stockdividend to PNMR of $4.1$15.4 million.

Investment in NM Renewable Development, LLC

As discussed in Note 1 of the 2017 Annual Reports on Form 10-K, PNMR Development and AEP OnSite Partners created NMRD in September 2017 to pursue the acquisition, development, and ownership of renewable energy projects, primarily in the state of New Mexico. NMRD’s current renewable energy capacity in operation is 31.8 MW. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. The investment in NMRD is accounted for using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over NMRD and its operations.

In the six months ended June 30, 2018, PNMR Development made cash contributions of $8.0 million to NMRD to be used primarily for its construction activities. For the three and six months ended June 30, 2018, NMRD had revenues of $1.1 million and $18.0$1.5 million and net earnings of $0.4 million and $0.5 million. At June 30, 2018, NMRD had $2.0 million of current assets, $47.9 million of property, plant, and equipment and other assets, $0.4 million of current liabilities, and $49.5 million of owners’ equity.

Cash and Restricted Cash

Additional information concerning the Company’s policy for recording cash and cash equivalents is discussed in Note 1 of the 2017 Annual Reports on Form 10-K. In November 2016, the FASB issued Accounting Standards Update 2016-18 – Statement of Cash Flows (Topic 230), which requires amounts generally described as restricted cash and restricted cash equivalents (collectively, “restricted cash”) to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statements of cash flows and adds disclosures necessary to reconcile such amounts to cash and cash equivalents on the balance sheets. ASU 2016-18 does not require that restricted cash be reflected as cash in the ninestatement of financial position and does not provide a definition of what should be considered restricted cash.

During 2015, PNM received a deposit of $8.2 million from a third party that was restricted for PNM’s construction of transmission interconnection facilities for that party. During 2016, PNM utilized $7.2 million of such third-party deposits to offset construction costs for the interconnection facilities. The remaining $1.0 million was held as restricted cash until the second quarter of 2017, at which time a refund was made to the third party. The balances of this deposit arrangement were included in other current assets on the balance sheets of PNMR and PNM. Under the terms of the BTMU Term Loan Agreement (Note 9), all cash of NM Capital was restricted to be used for payments required under that agreement or for taxes and fees. On May 22, 2018, Westmoreland repaid the Westmoreland Loan in full. NM Capital used a portion of the proceeds to repay all its obligations under the BTMU Term Loan Agreement. These payments effectively terminated the loan agreements. Cash held by NM Capital was included in cash and cash equivalents on the balance sheets of PNMR and was less than $0.1 million at December 31, 2017.

The Company adopted ASU 2016-18 as of January 1, 2018, its required effective date. Upon adoption, ASU 2016-18 requires the use of a retrospective transition method for the statement of cash flows in each period presented. Accordingly, PNM made retrospective adjustments to its Condensed Consolidated Statements of Cash Flows to increase beginning cash, restricted cash, and equivalents at January 1, 2017 by $1.0 million and to reduce operating cash in-flows – other current assets by $1.0 million during the six months ended Septemberending June 30, 2016.2017. In addition, the nine months ended September 30, 2016, PNMRbeginning and ending balances of cash, restricted cash, and equivalents are presented on the Condensed Consolidated Statements of Cash Flows. No other changes were made equity contributionsto the Condensed Consolidated Financial Statements in connection with the adoption of $28.1 million to ASU 2016-18.

PNM and $50.0 million to TNMP.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)


New Accounting Pronouncements

Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. The Company does not expect difficulty in adopting these standards by their required effective dates.

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

In May 2014, the FASB issued ASU 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. ASU 2014-09 also revises the disclosure requirements regarding revenue. Since the issuance of ASU 2014-09, the FASB issued a one-year deferral of the effective date and has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. When it becomes effective, the new standard will replace most existing revenue recognition guidance in GAAP. ASU 2014-09 can be applied retrospectively to each prior period presented or on a modified retrospective basis with a cumulative effect adjustment to retained earnings on the date of adoption. The Company anticipates adopting ASU 2014-09 on January 1, 2018, its required effective date, using the modified retrospective method of adoption.
The Company has substantially completed its assessment of ASU 2014-09, but, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding certain industry specific issues. These industry specific issues include the impacts of the new guidance on its accounting for CIAC and the presentation of revenues associated with “alternative revenue programs,” which primarily result from the Company’s approved rate rider programs. Although conclusions have not been finalized, the Company does not anticipate a material change in revenue recognition under the new requirements. The Company continues to analyze the financial statement presentation and disclosure requirements of ASU 2014-09.

Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10):Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, which makes targeted improvements to GAAP regarding financial instruments. ASU 2016-01 eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and requires those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. ASU 2016-01 also revises certain presentation and disclosure requirements. Under ASU 2016-01, accounting for investments in debt securities remains essentially unchanged. PNM currently classifies the investments held in the NDT and coal mine reclamation trusts as available-for-sale securities. Unrealized losses on these securities are recorded immediately through earnings and unrealized gains are recorded in AOCI until the securities are sold. The Company will adopt ASU 2016-01 on January 1, 2018, its required effective date. At that time any unrealized gains, net of income taxes, recorded in AOCI related to equity securities will be reclassified to retained earnings as a cumulative effect adjustment and future changes in the value of equity securities will be recorded in earnings. The amount of the cumulative adjustment upon adoption will depend on the amounts recorded in AOCI at that time, but PNM had unrealized gains on equity securities, net of income taxes, recorded in AOCI of $9.8 million at September 30, 2017.


PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Accounting Standards Update 2016-02 – Leases (Topic 842)

In February 2016, the FASB issued ASU 2016-02 to provide guidance on the recognition, measurement, presentation, and disclosure of leases. ASU 2016-02 will require that a liability be recorded on the balance sheet for all leases, based on the present value of future lease obligations. A corresponding right-of-use asset will also be recorded. Amortization of the lease obligation and the right-of-use asset for certain leases, primarily those classified as operating leases, will be on a straight-line basis, which is not expected to have a significant impact on the statements of earnings, or cash flows, whereas other leases will be required to be accounted for as financing arrangements similar to the accounting treatment for capital leases under current GAAP. ASU 2016-02 also revises certain disclosure requirements. Although early adoption of the standard is permitted, the Company does not plan to adopt this standard prior to January 1, 2019, its required effective date. At adoption of ASU 2016-02 originally required that leases will be recognized and measured as of the earliest period presented using a modified retrospective approach. This approach requireswith all periods presented to bebeing restated and presented under the new guidance, butguidance. The ASU allows entities to apply certain practical expedients to arrangements that exist upon adoption or that expired during the periods presented.
  
As further discussed in Note 7 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K, the Company has operating leases of office buildings, vehicles, and equipment. The Company also routinely enters into land easements and right-of-way agreements, but only a limited number of these agreements are considered leases under the current guidance. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. In addition, the Company also routinely enters into land easements and right-of-way agreements.

The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification, including the treatment of land easements under ASU 2016-02.clarification. The Company has formed a project team, conductedis conducting outreach activities across its lines of business, and is in the process of implementing software to help administer and account for its leasing activities. The Company has made significant progress in identifying arrangements, in addition to its existing operating lease arrangements that may be classified as leases under ASU 2016-02.2016-02 in addition to those currently classified as operating leases. It is likely the arrangements currently classified as leases will continue to be recognized as leases under ASU 2016-02. It is possible that other contractual arrangements not previously meeting the lease definition may contain elements that qualify as leases and that previously identified operating leases may be classified as financing leases under ASU 2016-02. The Company is in the process of analyzing each of the identified contractual arrangementarrangements to determine if it contains lease elements under the new standard and quantifying the potential impacts of identified lease arrangements. The Company is also evaluating the practical expedients, if any, it will elect upon adoption. The Company anticipates this process will continue intothroughout 2018. The Company will adopt this standard effective as of January 1, 2019, its required effective date.

In January 2018, the FASB issued ASU 2018-01, which clarifies that land easements are to be evaluated under ASU 2016-02, but provides an additional optional practical expedient to not evaluate existing or expired land easements that were not accounted for as leases under the current guidance. The Company has numerous land easements and right-of-way agreements that would fall under this clarification. The only such agreement that has been accounted for as a lease under current guidance is the right-of-way agreement with the Navajo Nation, which is discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. The Company anticipates it will elect to use the practical expedient for its existing and expired land easements upon adoption of ASU 2016-02.

In July 2018, the FASB issued ASU 2018-11, which provides entities an optional transitional relief method to apply ASU 2016-02 as of the date of initial application of the standard rather than as of the earliest period presented. The Company is evaluating this update and has not yet determined if it will elect to use this optional transitional relief method.

Accounting Standards Update 2016-13 – Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, which changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. The Company anticipates adopting ASU 2016-13 oneffective as of January 1, 2020, its required effective date, although early adoption is permitted beginning on January 1, 2019. The Company

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)


is in the process of analyzing the impacts of this new standard, but does not anticipate it will have a significant impact on its financial statements.

Accounting Standards Update 2016-18 – Statement of Cash Flows (Topic 230): Restricted Cash

In November 2016, the FASB issued ASU 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statements of cash flows and adds disclosures necessary to reconcile such amounts to cash and cash equivalents on the balance sheets. ASU 2016-18 does not provide a definition of what should be considered restricted cash. Upon adoption, ASU 2016-18 requires the use of a retrospective transition method for each period presented. The Company continues to analyze the impacts of ASU 2016-18, but does not believe the new standard will have a significant impact on its financial statements. The Company will adopt ASU 2016-18 on January 1, 2018, its required effective date.

Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment

In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of a quantitative impairment test requires an entity to compare the fair value of each reporting unit containing goodwill 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

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)


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 requires 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. ASU 2017-04 eliminates the second step of the impairment analysis. Accordingly, if the first step of a quantitative goodwill impairment analysis performed after adoption of ASU 2017-04 indicates that the fair value of a reporting unit is less than its carrying value, the goodwill of that reporting unit would be impaired to the extent of that difference. The Company anticipates it will adopt ASU 2017-04 for impairment testing after January 1, 2020, its required effective date, although early adoption is permitted. However, if there is an indication of potential impairment of goodwill as a result of an impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this standard.

Accounting Standards Update 2017-07 – Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07 to improve the presentation of net periodic pension and other postretirement benefit costs. Currently, the Company presents all of its net periodic benefit costs, net of amounts capitalized to construction and other accounts, as administrative and general expenses on its statements of earnings. The amendments in ASU 2017-07 require the service cost component of net benefit costs be presented in the same line item or items as employees’ compensation. The other components of net benefit cost (the “non-service cost components”) are required to be presented in the income statement separately from the service cost component and outside of operating income with disclosures identifying where the non-service cost components have been presented. ASU 2017-07 also limits capitalization to only the service cost component of benefit costs. PNMR and its subsidiaries maintain qualified defined benefit pension and OPEB plans. Currently, net periodic benefit cost for the Company’s defined benefit pension plans do not include a service cost component and there is only a minor amount of service cost for the OPEB plans. Additional information about the Company’s benefit plans is discussed in Note 12 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 10. ASU 2017-07 requires retrospective presentation of the service and non-service cost components of net benefit costs in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit costs. The Company believes PNM and TNMP can continue to capitalize the non-service cost components of net benefit costs as regulatory assets to the extent attributable to regulated operations and does not anticipate ASU 2017-07 will have a significant impact on its financial statements. The Company will adopt the standard on January 1, 2018, its required effective date.
Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued ASU 2017-12 to better align hedge accounting with an organization’s risk management activities and to simplify the application of hedge accounting guidance. ASU 2017-12 is effective for the Company on January 1, 2019 although early adoption is permitted beginning on January 1, 2018. At adoption, ASU 2017-12 is to be applied prospectively and allows entities to record a cumulative-effect adjustment at the transition date as well as allowing entities to elect certain practical expedients upon adoption. As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K and in Note 9, the Company periodically enters into, and designates as cash flow hedges, interest rate swaps to hedge its exposure to changes in interest rates. In addition, as discussed in Note 8 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K and in Note 7, the Company enters into various derivative instruments to economically hedge the risk of changes in commodity prices, which are not currently designated as cash flow hedges. The Company is evaluating the requirements of ASU 2017-12, but does not anticipate the changes will have a significant impact on the Company’s accounting treatment for derivative instruments or on its financial statements.

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


(2)Earnings Per Share

In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows:
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (In thousands, except per share amounts)
Net Earnings Attributable to PNMR$73,739
 $54,418
 $134,156
 $92,040
Average Number of Common Shares:       
Outstanding during period79,654
 79,654
 79,654
 79,654
    Vested awards of restricted stock
284
 96
 215
 99
Average Shares – Basic79,938
 79,750
 79,869
 79,753
Dilutive Effect of Common Stock Equivalents:       
Stock options and restricted stock216
 367
 263
 377
Average Shares – Diluted80,154
 80,117
 80,132
 80,130
Net Earnings Per Share of Common Stock:       
Basic$0.92
 $0.68
 $1.68
 $1.15
Diluted$0.92
 $0.68
 $1.67
 $1.15

(3)(2)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 includes the generation and sale of electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity includes the asset optimization of PNM’s jurisdictional capacity, as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale power and transmission rates.

TNMP
TNMP is an electric utility providing services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. TNMP also provides transmission services at regulated rates to other utilities that interconnect with TNMP’s facilities.

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)


Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. The activities of PNMR Development, and NM Capital, and the equity method investment in NMRD are also included in Corporate and Other. Eliminations of intercompany income and expense transactions are reflected in the Corporate and Other segment.

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


PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


PNMR SEGMENT INFORMATION
PNM TNMP 
Corporate
and Other
 ConsolidatedPNM TNMP 
Corporate
and Other
 PNMR Consolidated
(In thousands)(In thousands)
Three Months Ended September 30, 2017 
Three Months Ended June 30, 2018 
Electric operating revenues$327,254
 $92,646
 $—
 $419,900
$264,511
 $87,802
 $—
 $352,313
Cost of energy82,367
 21,381
 —
 103,748
66,361
 21,350
 —
 87,711
Utility margin244,887
 71,265
 —
 316,152
198,150
 66,452
 —
 264,602
Other operating expenses94,871
 25,367
 (5,391) 114,847
107,058
 23,510
 (5,358) 125,210
Depreciation and amortization36,764
 16,424
 5,633
 58,821
38,213
 16,113
 5,737
 60,063
Operating income (loss)113,252
 29,474
 (242) 142,484
52,879
 26,829
 (379) 79,329
Interest income1,782
 —
 1,800
 3,582
3,381
 —
 958
 4,339
Other income (deductions)6,342
 1,228
 (460) 7,110
(3,146) 832
 (428) (2,742)
Interest charges(20,451) (7,704) (3,951) (32,106)(19,988) (7,801) (5,532) (33,321)
Segment earnings (loss) before income taxes100,925
 22,998
 (2,853) 121,070
33,126
 19,860
 (5,381) 47,605
Income taxes (benefit)35,642
 8,271
 (1,170) 42,743
2,345
 4,493
 (1,682) 5,156
Segment earnings (loss)65,283
 14,727
 (1,683) 78,327
30,781
 15,367
 (3,699) 42,449
Valencia non-controlling interest(4,456) —
 —
 (4,456)(4,109) —
 —
 (4,109)
Subsidiary preferred stock dividends(132) —
 —
 (132)(132) —
 —
 (132)
Segment earnings (loss) attributable to PNMR$60,695
 $14,727
 $(1,683) $73,739
$26,540
 $15,367
 $(3,699) $38,208
              
Nine Months Ended September 30, 2017       
Six Months Ended June 30, 2018       
Electric operating revenues$854,909
 $257,489
 $—
 $1,112,398
$500,742
 $169,449
 $—
 $670,191
Cost of energy246,635
 64,183
 —
 310,818
137,163
 43,104
 —
 180,267
Utility margin608,274
 193,306
 —
 801,580
363,579
 126,345
 —
 489,924
Other operating expenses288,300
 72,188
 (15,286) 345,202
207,569
 48,484
 (10,375) 245,678
Depreciation and amortization109,228
 47,392
 16,209
 172,829
74,840
 32,500
 11,445
 118,785
Operating income (loss)210,746
 73,726
 (923) 283,549
81,170
 45,361
 (1,070) 125,461
Interest income6,457
 —
 5,891
 12,348
5,868
 —
 2,594
 8,462
Other income (deductions)19,924
 2,392
 (918) 21,398
(1,927) 1,916
 (349) (360)
Interest charges(62,393) (22,619) (11,125) (96,137)(40,818) (15,530) (10,028) (66,376)
Segment earnings (loss) before income taxes174,734
 53,499
 (7,075) 221,158
44,293
 31,747
 (8,853) 67,187
Income taxes (benefit)58,865
 18,964
 (2,675) 75,154
1,997
 6,968
 (3,026) 5,939
Segment earnings (loss)115,869
 34,535
 (4,400) 146,004
42,296
 24,779
 (5,827) 61,248
Valencia non-controlling interest(11,452) —
 —
 (11,452)(7,786) —
 —
 (7,786)
Subsidiary preferred stock dividends(396) —
 —
 (396)(264) —
 —
 (264)
Segment earnings (loss) attributable to PNMR$104,021
 $34,535
 $(4,400) $134,156
$34,246
 $24,779
 $(5,827) $53,198
              
At September 30, 2017:       
At June 30, 2018:       
Total Assets$5,023,816
 $1,465,219
 $208,219
 $6,697,254
$4,994,277
 $1,583,311
 $172,501
 $6,750,089
Goodwill$51,632
 $226,665
 $—
 $278,297
$51,632
 $226,665
 $—
 $278,297

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
 ConsolidatedPNM TNMP 
Corporate
and Other
 PNMR Consolidated
(In thousands)(In thousands)
Three Months Ended September 30, 2016       
Three Months Ended June 30, 2017       
Electric operating revenues$311,276
 $89,098
 $—
 $400,374
$276,097
 $86,223
 $��
 $362,320
Cost of energy88,565
 20,201
 —
 108,766
82,952
 21,315
 —
 104,267
Utility margin222,711
 68,897
 —
 291,608
193,145
 64,908
 —
 258,053
Other operating expenses109,342
 24,184
 (3,006) 130,520
95,395
 23,025
 (5,235) 113,185
Depreciation and amortization33,312
 16,354
 3,351
 53,017
36,448
 15,597
 5,580
 57,625
Operating income (loss)80,057
 28,359
 (345) 108,071
61,302
 26,286
 (345) 87,243
Interest income1,509
 —
 3,095
 4,604
1,858
 —
 2,027
 3,885
Other income (deductions)4,980
 855
 (184) 5,651
3,762
 432
 (123) 4,071
Interest charges(22,213) (7,308) (2,946) (32,467)(20,931) (7,510) (3,891) (32,332)
Segment earnings (loss) before income taxes64,333
 21,906
 (380) 85,859
45,991
 19,208
 (2,332) 62,867
Income taxes19,343
 8,053
 (93) 27,303
15,515
 7,004
 (883) 21,636
Segment earnings (loss)44,990
 13,853
 (287) 58,556
30,476
 12,204
 (1,449) 41,231
Valencia non-controlling interest(4,006) —
 —
 (4,006)(3,544) —
 —
 (3,544)
Subsidiary preferred stock dividends(132) —
 —
 (132)(132) —
 —
 (132)
Segment earnings (loss) attributable to PNMR$40,852
 $13,853
 $(287) $54,418
$26,800
 $12,204
 $(1,449) $37,555
              
Nine Months Ended September 30, 2016       
Six Months Ended June 30, 2017       
Electric operating revenues$780,228
 $246,498
 $—
 $1,026,726
$527,655
 $164,843
 $—
 $692,498
Cost of energy222,376
 60,122
 —
 282,498
164,268
 42,802
 —
 207,070
Utility margin557,852
 186,376
 —
 744,228
363,387
 122,041
 —
 485,428
Other operating expenses314,961
 70,328
 (9,261) 376,028
189,151
 46,822
 (9,894) 226,079
Depreciation and amortization97,778
 45,760
 10,263
 153,801
72,464
 30,968
 10,576
 114,008
Operating income (loss)145,113
 70,288
 (1,002) 214,399
101,772
 44,251
 (682) 145,341
Interest income8,549
 —
 9,871
 18,420
4,675
 —
 4,091
 8,766
Other income (deductions)17,305
 2,139
 (1,517) 17,927
9,306
 1,165
 (459) 10,012
Interest charges(66,494) (22,150) (8,535) (97,179)(41,943) (14,915) (7,173) (64,031)
Segment earnings (loss) before income taxes104,473
 50,277
 (1,183) 153,567
73,810
 30,501
 (4,223) 100,088
Income taxes (benefit)32,131
 18,460
 (497) 50,094
23,223
 10,693
 (1,505) 32,411
Segment earnings (loss)72,342
 31,817
 (686) 103,473
50,587
 19,808
 (2,718) 67,677
Valencia non-controlling interest(11,037) —
 —
 (11,037)(6,996) —
 —
 (6,996)
Subsidiary preferred stock dividends(396) —
 —
 (396)(264) —
 —
 (264)
Segment earnings (loss) attributable to PNMR$60,909
 $31,817
 $(686) $92,040
$43,327
 $19,808
 $(2,718) $60,417
              
At September 30, 2016:       
At June 30, 2017:       
Total Assets$4,799,012
 $1,366,840
 $237,818
 $6,403,670
$4,939,407
 $1,437,547
 $207,491
 $6,584,445
Goodwill$51,632
 $226,665
 $—
 $278,297
$51,632
 $226,665
 $—
 $278,297

The Company defines utility margin as electric operating revenues less cost of energy. Cost of energy consists primarily of fuel and purchase power costs for PNM and costs charged by third-party transmission providers for TNMP. The Company believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since substantially all such costs are offset in revenues as fuel and purchase power costs are passed through to customers under PNM’s FPPAC and third-party transmission costs are passed on to customers through TNMP’s transmission cost recovery factor. Utility margin is not a financial measure required to be presented under GAAP and is considered a non-GAAP measure.


PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


(4)(3)Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the ninesix months ended SeptemberJune 30, 20172018 and 20162017 is as follows:
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss)
PNM PNMRPNM PNMR
Unrealized     Fair Value  Unrealized     Fair Value  
Gains on     Adjustment  Gains on     Adjustment  
Available-for- Pension   for Cash  Available-for- Pension   for Cash  
Sale Liability   Flow  Sale Liability   Flow  
Securities Adjustment Total Hedges TotalSecurities Adjustment Total Hedges Total
(In thousands)(In thousands)
Balance at December 31, 2016$4,320
 $(96,748) $(92,428) $(23) $(92,451)
Balance at December 31, 2017, as originally reported$13,169
 $(110,262) $(97,093) $1,153
 $(95,940)
Cumulative effect adjustment (Note 7)(11,208) —
 (11,208) —
 (11,208)
Balance at January 1, 2018, as adjusted1,961
 (110,262) (108,301) 1,153
 (107,148)
Amounts reclassified from AOCI (pre-tax)(11,088) 4,839
 (6,249) 484
 (5,765)(3,126) 3,788
 662
 (7) 655
Income tax impact of amounts reclassified4,302
 (1,878) 2,424
 (187) 2,237
794
 (962) (168) 1
 (167)
Other OCI changes (pre-tax)22,302
 —
 22,302
 (278) 22,024
1,472
 —
 1,472
 2,420
 3,892
Income tax impact of other OCI changes(8,654) —
 (8,654) 108
 (8,546)(374) —
 (374) (615) (989)
Net after-tax change6,862
 2,961
 9,823
 127
 9,950
(1,234) 2,826
 1,592
 1,799
 3,391
Balance at September 30, 2017$11,182
 $(93,787) $(82,605) $104
 $(82,501)
Balance at June 30, 2018$727
 $(107,436) $(106,709) $2,952
 $(103,757)
 
Balance at December 31, 2015$17,346
 $(88,822) $(71,476) $44
 $(71,432)
Balance at December 31, 2016$4,320
 $(96,748) $(92,428) $(23) $(92,451)
Amounts reclassified from AOCI (pre-tax)(10,135) 4,128
 (6,007) 573
 (5,434)(6,961) 3,226
 (3,735) 323
 (3,412)
Income tax impact of amounts reclassified3,955
 (1,611) 2,344
 (224) 2,120
2,701
 (1,252) 1,449
 (125) 1,324
Other OCI changes (pre-tax)3,115
 —
 3,115
 (1,305) 1,810
14,903
 —
 14,903
 (288) 14,615
Income tax impact of other OCI changes(1,216) —
 (1,216) 509
 (707)(5,783) —
 (5,783) 112
 (5,671)
Net after-tax change(4,281) 2,517
 (1,764) (447) (2,211)4,860
 1,974
 6,834
 22
 6,856
Balance at September 30, 2016$13,065
 $(86,305) $(73,240) $(403) $(73,643)
Balance at June 30, 2017$9,180
 $(94,774) $(85,594) $(1) $(85,595)

Pre-taxThe Condensed Consolidated Statements of Earnings include pre-tax amounts reclassified from AOCI related to “UnrealizedUnrealized Gains on Available-for-Sale Securities” are includedSecurities in “Gainsgains (losses) on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCIinvestment securities, related to “PensionPension Liability Adjustment” are reclassified to “Operating Expenses – AdministrativeAdjustment in other (deductions), and general” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “FairFair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges”Hedges in the Condensed Consolidated Statements of Earnings. An insignificant amount is included in capitalized interest.interest charges. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes”income taxes in the Condensed Consolidated Statements of Earnings.

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


(4)Earnings Per Share

In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows:
 Three Months Ended Six Months Ended
 June 30, June 30,
 2018 2017 2018 2017
 (In thousands, except per share amounts)
Net Earnings Attributable to PNMR$38,208
 $37,555
 $53,198
 $60,417
Average Number of Common Shares:       
Outstanding during period79,654
 79,654
 79,654
 79,654
    Vested awards of restricted stock
211
 251
 208
 181
Average Shares – Basic79,865
 79,905
 79,862
 79,835
Dilutive Effect of Common Stock Equivalents:       
Stock options and restricted stock114
 226
 134
 286
Average Shares – Diluted79,979
 80,131
 79,996
 80,121
Net Earnings Per Share of Common Stock:       
Basic$0.48
 $0.47
 $0.67
 $0.76
Diluted$0.48
 $0.47
 $0.67
 $0.75

(5)Electric Operating Revenues

PNMR is an investor-owned holding company with two regulated utilities providing electricity and electric services in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP.

Revenue Recognition

Electric operating revenues are recorded in the period of energy delivery, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. The determination of the energy sales billed to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. Unbilled electric revenue is estimated based on the daily generation volumes, estimated customer usage by class, line losses, and applicable customer rates reflecting historical trends and experience. Amounts billed are generally due within the next month. The Company does not incur incremental costs to obtain contracts for its energy services.

PNM’s wholesale electricity sales are recorded as electric operating revenues and wholesale electricity purchases are recorded as costs of energy sold. In accordance with GAAP, derivative contracts that are subject to unplanned netting are recorded net in earnings. A “book-out” is the planned or unplanned netting of off-setting purchase and sale transactions. A book-out is a transmission mechanism to reduce congestion on the transmission system or administrative burden. For accounting purposes, a book-out is the recording of net revenues upon the settlement of a derivative contract.

Unrealized gains and losses on derivative contracts that are not designated for hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power and fuel supply agreements, used to hedge generation assets and purchased power costs. Changes in the fair value of economic hedges are reflected in results of operations, with changes related to economic hedges on sales included in operating revenues and changes related to economic hedges on purchases included in cost of energy sold (Note 7).

In May 2014, the FASB issued ASU 2014-09 – Revenue from Contracts with Customers (Topic 606). 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. ASU 2014-09 also revises the disclosure requirements regarding revenue and requires that revenue from contracts with customers be reported separately from other revenues. ASU 2014-09 provides that it could be applied retrospectively to each prior period presented or on a modified retrospective basis with a cumulative effect adjustment to retained earnings on the date of adoption.

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)



The Company adopted ASU 2014-09 effective as of January 1, 2018, its required effective date, using the modified retrospective method of adoption. The adoption of ASU 2014-09 did not result in changes to the nature, amount, and timing of the Company’s existing revenue recognition processes or information technology infrastructure. Therefore, the adoption of ASU 2014-09 had no effect on the amount of revenue recorded in 2018 compared to the amount that would have been recorded under prior GAAP, no effect on total electric operating revenues or any other caption within the Company’s financial statements, and no cumulative effect adjustment was recorded. Revenues for 2018 are presented in accordance with the standard on the Condensed Consolidated Statements of Earnings and 2017 revenues are presented on a comparative basis. Additional disclosures to further disaggregate 2018 revenues are presented below.

Under ASU 2014-09, PNM and TNMP recognize revenue as they satisfy performance obligations, which typically occurs as the customer or end-user consumes the electric service provided. Electric services are typically for a bundle of services that are distinct and transferred to the end-user in one performance obligation measured by KWh or KW. Electric operating revenues are recorded in the period of energy delivery, including estimated unbilled amounts. As permitted under GAAP, the Company has elected to exclude all sales and similar taxes from revenue.

Revenue from contracts with customers is recorded based upon the total authorized tariff price at the time electric service is rendered, including amounts billed under arrangements qualifying as an Alternative Revenue Program (“ARP”). ARP arrangements are agreements between PNM or TNMP and its regulator that allows PNM or TNMP to adjust future rates in response to past activities or completed events, if certain criteria are met. GAAP requires that ARP revenues be reported separately from contracts with customers. ARP revenues in a given period include the recognition of “originating” ARP revenues (i.e. when the regulator-specific conditions are met) in the period, offset by the reversal of ARP revenues billed to customers in that period.

Sources of Revenue

Additional information about the nature of revenues is provided below.

Revenue from Contracts with Customers

PNM

NMPRC Regulated Retail Electric Service – PNM provides electric generation, transmission, and distribution service to its rate-regulated customers in New Mexico. PNM’s retail electric service territory covers a large area of north central New Mexico, including the cities of Albuquerque, Rio Rancho, and Santa Fe, and certain areas of southern New Mexico. Customer rates for retail electric service are set by the NMPRC and revenue is recognized as energy is delivered to the customer. PNM invoices customers on a monthly basis for electric service and generally collects billed amounts within one month.

Transmission Service to Third Parties – PNM owns transmission lines that are interconnected with other utilities in New Mexico, Texas, Arizona, Colorado, and Utah. Transmission customers receive service for the transmission of energy owned by the customer utilizing PNM’s transmission facilities. Customers generally receive transmission services, which are regulated by FERC, from PNM through PNM’s Open Access Transmission Tariff (“OATT”) or a specific contract. Customers are billed based on capacity and energy components on a monthly basis.

Other –On January 1, 2018, PNM acquired a 65 MW interest in SJGS Unit 4, which is held as merchant plant as ordered by the NMPRC (Note 11). PNM sells power from 36 MW of this capacity to a third party at a fixed price that is recorded as revenue from contracts with customers. PNM is obligated to deliver power under this arrangement only when SJGS Unit 4 is operating. To the extent the remainder of this 65 MW interest is used to serve PNM’s retail load requirements, revenue is recorded as revenues from contracts with customers. Other market sales from this 65 MW interest are recorded in other electric operating revenues.

TNMP

PUCT Regulated Retail Electric Service – TNMP provides transmission and distribution services in Texas under the provisions of TECA and the Texas Public Utility Regulatory Act. TNMP is subject to traditional cost-of-service regulation with respect to rates and service under the jurisdiction of the PUCT and certain municipalities. TNMP’s transmission and distribution activities are solely within ERCOT, which is the independent system operator responsible for maintaining reliable operations for the bulk electric power supply system in most of Texas. Therefore, TNMP is not subject to traditional rate regulation by FERC.

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. Revenue is recognized as energy is delivered to the consumer. Delivery of service is invoiced as the transaction occurs and is generally paid within a month.

Transmission Cost of Service (“TCOS”) – TNMP is a transmission service provider that is allowed to recover its TCOS through a network transmission rate that is approved by the PUCT. TCOS customers are other utilities that receive service for the transmission of energy owned by the customer utilizing TNMP’s transmission facilities. Historically, TNMP has updated its transmission rates twice per year to reflect changes in its invested capital although updates are not allowed while a general rate case is in progress. See (Note 12).

Alternative Revenue Programs

ARP revenues, which are discussed above, include recovery or refund provisions under PNM’s renewable energy rider and true-ups to PNM’s formula transmission rates; TNMP’s AMS surcharge, transmission cost recovery factor, and rate impacts of the 2017 change in the corporate income tax rate; and the energy efficiency incentive bonus at both PNM and TNMP. GAAP provides for the recognition of regulatory assets and liabilities for the difference between ARP revenues and amounts billed under those programs. Regulatory assets and liabilities are amortized into earnings as amounts are billed. Accordingly, the Company has deferred certain costs and recorded certain liabilities pursuant to the rate actions of the NMPRC, PUCT, and FERC.

Other Electric Operating Revenues

Other electric operating revenues consist primarily of PNM’s sales for resale meeting the definition of a derivative under GAAP. Derivatives are not considered contracts with customers under ASU 2014-09. PNM engages in activities meeting the definition of derivatives to optimize its existing jurisdictional assets and long-term power agreements through spot market, hour-ahead, day-ahead, week-ahead, month-ahead, and other sales of any excess generation not required to fulfill retail load and contractual commitments. Through December 31, 2017, PNM’s 134 MW share of Unit 3 at PVNGS was excluded from retail rates and was being sold in the wholesale market. In December 2015, the NMPRC approved PNM’s request to include PVNGS Unit 3 as a jurisdictional resource to service New Mexico retail customers beginning in 2018.

Disaggregation of Revenues

A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects ARP revenues and other revenues.
  PNM TNMP PNMR Consolidated
Three Months Ended June 30, 2018 (In thousands)
Electric Operating Revenues:      
Contracts with customers:      
Retail electric revenue      
Residential $99,508
 $31,315
 $130,823
Commercial 110,652
 28,082
 138,734
Industrial 14,597
 4,184
 18,781
Public authority 5,220
 1,399
 6,619
Economy energy service 6,378
 —
 6,378
Transmission 14,108
 16,743
 30,851
Miscellaneous 4,265
 2,208
 6,473
Total revenues from contracts with customers 254,728
 83,931
 338,659
Alternative revenue programs 1,789
 3,871
 5,660
Other electric operating revenues 7,994
 —
 7,994
Total Electric Operating Revenues $264,511
 $87,802
 $352,313


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 PNMR Consolidated
Six Months Ended June 30, 2018 (In thousands)
Electric Operating Revenues:      
Contracts with customers:      
Retail electric revenue      
Residential $196,676
 $60,581
 $257,257
Commercial 193,501
 55,234
 248,735
Industrial 28,056
 8,489
 36,545
Public authority 9,855
 2,815
 12,670
Economy energy service 13,666
 —
 13,666
Transmission 26,590
 33,251
 59,841
Miscellaneous 8,947
 4,349
 13,296
Total revenues from contracts with customers 477,291
 164,719
 642,010
Alternative revenue programs 1,854
 4,730
 6,584
Other electric operating revenues 21,597
 —
 21,597
Total Electric Operating Revenues $500,742
 $169,449
 $670,191

Contract balances

Performance obligations related to contracts with customers are typically satisfied when the energy is delivered and the customer or end-user utilizes the energy. Accounts receivable from customers represent amounts billed to the customer or end-user, including amounts under ARP programs. For PNM, accounts receivable reflected on the Condensed Consolidated Balance Sheets includes $62.3 million at June 30, 2018 and $62.9 million at December 31, 2017 resulting from contracts with customers. All of TNMP’s accounts receivable results from contracts with customers.

Contract assets are an entity’s right to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditioned on something other than the passage of time (for example, the entity’s future performance). The Company has no contract assets as of June 30, 2018. Contract liabilities arise when consideration is received in advance from a customer before satisfying the performance obligations. Therefore, revenue is deferred and not recognized until the obligation is satisfied. Under its OATT, PNM accepts upfront consideration for capacity reservations requested by transmission customers, which requires PNM to defer the customer’s transmission capacity rights for a specific period of time. PNM recognizes the revenue of these capacity reservations over the period it defers the customer’s capacity rights. Other utilities pay PNM and TNMP in advance for the joint-use of their utility poles. These revenues are recognized over the period of time specified in the joint-use contract, typically for one calendar year. Deferred revenues on these arrangements are recorded as contract liabilities. The Company has no other arrangements with remaining performance obligations to which a portion of the transaction price would be required to be allocated.

Changes during the period in the balances of contract liabilities, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, are as follows:
  PNM TNMP PNMR Consolidated
  (In thousands)
Balance at December 31, 2017 $349
 $—

$349
Consideration received in advance of service to be provided 3,987
 1,512
 5,499
Deferred revenue earned (2,210) (756) (2,966)
Balance at June 30, 2018 $2,126
 $756

$2,882


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)


(6)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 (“VIE”). GAAP also requires continual reassessment of the primary beneficiary of a VIE. Additional information concerning PNM’s VIEs is contained in Note 9 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K.

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 partythird-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operation and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and ninesix months ended SeptemberJune 30, 2017,2018, PNM paid $4.9 million and $14.7$9.8 million for fixed charges and $0.9$0.6 million and $1.2$0.9 million for variable charges. For the three and ninesix months ended SeptemberJune 30, 2016,2017, PNM paid $4.9 million and $14.5$9.8 million for fixed charges and $0.5$0.2 million and $1.1$0.3 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy its obligations and creditors of Valencia do not have any recourse against PNM’s assets. During the term of the PPA, PNM has the option, under certain conditions, to purchase and own up to 50% of the plant or the VIE. The PPA specifies that the purchase price would be the greater of 50% of book value reduced by related indebtedness or 50% of fair market value.

PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. Therefore, PNM has concluded that the third-party entity that owns Valencia is a VIE 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 Valencia in its financial statements. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the Condensed Consolidated Financial Statements of PNM although PNM has no legal ownership interest or voting control of the VIE. 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,
 2017 2016 2017 2016
 (In thousands)
Operating revenues$5,859
 $5,356
 $15,880
 $15,541
Operating expenses(1,403) (1,350) (4,428) (4,504)
Earnings attributable to non-controlling interest$4,456
 $4,006
 $11,452
 $11,037
Three Months Ended June 30,Six Months Ended June 30,
2018201720182017
(In thousands)
Operating revenues$5,911
$5,094
$10,679
$10,021
Operating expenses(1,802)(1,550)(2,893)(3,025)
Earnings attributable to non-controlling interest$4,109
$3,544
$7,786
$6,996

 
Financial Position

 June 30, December 31,
 2018 2017
 (In thousands)
Current assets$3,304
 $2,688
Net property, plant, and equipment62,975
 64,109
Total assets66,279
 66,797
Current liabilities679
 602
Owners’ equity – non-controlling interest$65,600
 $66,195


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)


Westmoreland San Juan LLC (“WSJ”) and SJCC

As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS from SJCC under a coal supply agreement (“SJGS CSA”). That section includes information on the acquisition of SJCC by WSJ, a subsidiary of Westmoreland, on January 31, 2016, as well as the $125.0 million loan (the “Westmoreland Loan”) from NM Capital, a subsidiary of PNMR, to WSJ, which loan provided substantially all of the funds required for the SJCC purchase, and the issuance of $30.3 million in letters of credit to facilitate the issuance of reclamation bonds required in order for SJCC to mine coal to be supplied to SJGS. The Westmoreland Loan and the letters of credit support result in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital could be subject to possible loss in the event of a default by WSJ under the Westmoreland Loan and/or performance was required under the letter of credit support.  Principal payments under the Westmoreland Loan began on August 1, 2016 and were required quarterly thereafter. Interest was also paid quarterly beginning on May 3, 2016.

The Westmoreland Loan required that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it was fully repaid. As discussed in Note 11, the full principal outstanding under the Westmoreland Loan of $50.1 million was repaid on May 22, 2018. NM Capital used a portion of the proceeds to repay all remaining amounts owed under the BTMU Term Loan Agreement. These payments effectively terminated the loan agreements and PNMR’s guarantee of NM Capital’s obligations under the BTMU Term Loan Agreement. The Westmoreland Loan was secured by the assets of and the equity interests in SJCC. PNMR considers the possibility of loss under the letters of credit support to be remote since the purpose of posting the bonds is to provide assurance that SJCC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the SJGS CSA. Also, much of the mine reclamation activities will not be performed until after the expiration of the SJGS CSA. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations.

On April 2, 2018, Westmoreland filed its Annual Report on Form 10-K for the year ended December 31, 2017 with the SEC. In their Form 10-K, Westmoreland indicated that it retained financial advisors and restructuring advisors “to explore strategic alternatives to strengthen the Company’s balance sheet and maximize the value of the Company, which may include, but not limited to, seeking reorganization under Chapter 11 of the U.S. Bankruptcy Code.” On May 21, 2018, Westmoreland filed a Current Report on Form 8-K with the SEC indicating it had obtained a new credit agreement with certain of its existing creditors that provided Westmoreland with additional financing. In the May 21, 2018 Form 8-K Westmoreland indicated that “A portion of the proceeds of the Financing have been used to refinance in full the Company’s and its subsidiaries’ existing asset-based revolving credit facilities and Westmoreland San Juan, LLC’s existing term loan facility.” As mentioned above, the Westmoreland Loan was repaid in full in May 2018.
Both WSJ and SJCC are considered to be VIEs.  PNMR’s analysis of these arrangements concluded that Westmoreland, as the parent of WSJ, has the ability to direct the SJCC mining operations, which is the factor that most significantly impacts the economic performance of WSJ and SJCC.  NM Capital’s rights under the Westmoreland Loan were the typical protective rights of a lender, but did not give NM Capital any oversight over mining operations. Other than PNM being able to ensure that coal is supplied in adequate quantities and of sufficient quality to provide the fuel necessary to operate SJGS in a normal manner, the mining operations are solely under the control of Westmoreland and its subsidiaries, including developing mining plans, hiring of personnel, and incurring operating and maintenance expenses. Neither PNMR nor PNM has any ability to direct or influence the mining operation.  PNM’s involvement through the SJGS CSA is a protective right rather than a participating right and Westmoreland has the power to direct the activities that most significantly impact the economic performance of SJCC.  The SJGS CSA requires SJCC to deliver coal required to fuel SJGS in exchange for payment of a set price per ton, which is escalated over time for inflation.  If SJCC is able to mine more efficiently than anticipated, its economic performance will be improved.  Conversely, if SJCC cannot mine as efficiently as anticipated, its economic performance will be negatively impacted.  Accordingly, PNMR believes Westmoreland is the primary beneficiary of WSJ and, therefore, WSJ and SJCC are not consolidated by either PNMR or PNM. The amounts outstanding under the letter of credit support constitute PNMR’s maximum exposure to loss from the VIEs at June 30, 2018.

Financial Position
 September 30, December 31,
 2017 2016
 (In thousands)
Current assets$3,498
 $2,551
Net property, plant, and equipment64,818
 66,947
Total assets68,316
 69,498
Current liabilities907
 578
Owners’ equity – non-controlling interest$67,409
 $68,920

Westmoreland San Juan LLC (“WSJ”) and SJCC

As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS from SJCC under a coal supply agreement (“CSA”). That section includes information on the acquisition of SJCC by WSJ, a subsidiary of Westmoreland, on Ja

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)


nuary 31, 2016, as well as a $125.0 million loan (the “Westmoreland Loan”) from NM Capital, a subsidiary
(7)Fair Value of PNMR, to WSJ, which loan provided substantially all of the funds required for the SJCC purchase,Derivative and the issuance of $30.3 million in letters of credit to facilitate the issuance of reclamation bonds required in order for SJCC to mine coal to be supplied to SJGS. The Westmoreland Loan and the letters of credit support result in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital could be subject to possible lossOther Financial Instruments

Additional information concerning energy related derivative contracts and other financial instruments is contained in Note 8 of the Notes to Consolidated Financial Statements in the event of a default by WSJ under the Westmoreland Loan and/or performance was required under the letter of credit support.  Principal payments under the Westmoreland Loan began on August 1, 2016 and are required quarterly thereafter. Interest is also paid quarterly beginning on May 3, 2016.

At September 30, 2017 the amount outstanding under the Westmoreland Loan was $66.2 million. In addition, interest receivable of $1.2 million is included in Other receivables. The Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. A principal payment of $9.6 million plus interest of $1.8 million is due on November 1, 2017. As of October 20, 2017, $11.4 million was held in a SJCC bank account that is restricted solely to be used to service the Westmoreland Loan. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations.  In such event, NM Capital would likely engage a third-party mining company to operate SJCC so that operations of the mine are not disrupted. The acquisition of SJCC for approximately $125.0 million on January 31, 2016 was an arm’s-length negotiated transaction between Westmoreland and BHP, which amount should approximate the fair value of SJCC at the date of acquisition.  If WSJ were to default, NM Capital should be able to acquire assets of approximately the value of the Westmoreland Loan without a significant loss. Furthermore, PNMR considers the possibility of loss under the letters of credit support to be remote since the purpose of posting the bonds is to provide assurance that SJCC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the CSA. Also, much of the mine reclamation activities will not be performed until after the expiration of the CSA and the final maturity of the Westmoreland Loan. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations.

Both WSJ and SJCC are considered to be VIEs.  PNMR’s analysis of these arrangements concluded that Westmoreland, as the parent of WSJ, has the ability to direct the SJCC mining operations, which is the factor that most significantly impacts the economic performance of WSJ and SJCC.  NM Capital’s rights under the Westmoreland Loan are the typical protective rights of a lender, but do not give NM Capital any oversight over mining operations unless there is a default under the loan agreement. Other than PNM being able to ensure that coal is supplied in adequate quantities and of sufficient quality to provide the fuel necessary to operate SJGS in a normal manner, the mining operations are solely under the control of Westmoreland and its subsidiaries, including developing mining plans, hiring of personnel, and incurring operating and maintenance expenses. Neither PNMR nor PNM has any ability to direct or influence the mining operation.  Therefore, PNM’s involvement through the CSA is a protective right rather than a participating right and Westmoreland has the power to direct the activities that most significantly impact the economic performance of SJCC.  The CSA requires SJCC to deliver coal required to fuel SJGS in exchange for payment of a set price per ton, which is escalated over time for inflation.  If SJCC is able to mine more efficiently than anticipated, its economic performance will be improved.  Conversely, if SJCC cannot mine as efficiently as anticipated, its economic performance will be negatively impacted.  Accordingly, PNMR believes Westmoreland is the primary beneficiary of WSJ and, therefore, WSJ and SJCC are not consolidated by either PNMR or PNM. The amounts outstanding under the Westmoreland Loan and the letter of credit support constitute PNMR’s maximum exposure to loss from the VIEs.

(6)Lease Commitments

The Company leases office buildings, vehicles, and other equipment. In addition, PNM leases interests in Units 1 and 2 of PVNGS and certain right-of-way agreements are classified as leases. All of the Company’s leases are currently accounted for as operating leases. See New Accounting Pronouncements in Note 1. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, including PNM’s actions with regard to renewal and purchase options 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 exercised its fair market value options to purchase the assets underlying those leases on the expiration date of the original leases. On January 15, 2016, PNM paid $78.1

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)


million to the lessor under one lease for 31.3 MW of the entitlement from PVNGS Unit 2 and $85.2 million to the lessors under the other two leases for 32.8 MW of the entitlement from PVNGS Unit 2. See Note 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case.

PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, 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 lessors, and take title to the leased interests. If such an event had occurred as of September 30, 2017, amounts due to the lessors under the circumstances described above would be up to $169.9 million, payable on January 15, 2018 in addition to the scheduled lease payments due on January 15, 2018.

(7)Fair Value of Derivative and Other Financial Instruments

Additional information concerning energy related derivative contracts and other financial instruments is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K.

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.

Energy Related Derivative Contracts

Overview

The primary objective for the use of commodity derivative instruments, including energy contracts, options, swaps, 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. PNM’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its wholesale customers not covered under a FPPAC. However, as discussed below,

PNM has hedging arrangementswas exposed to market risk for the outputits share of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 will be included asbecame a jurisdictional resource to serve New Mexico retail customers.

Beginning January 1, 2018, PNM will beis exposed to market risk for theits 65 MW ofinterest in SJGS Unit 4, that will be transferred to PNM from PNMR Developmentwhich is held as merchant plant as ordered by the NMPRC (Note 11) on December 31, 2017. In anticipation of the transfer of ownership,. PNM entered into agreements to sell the power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022, subject to certain conditions. Under these agreements, PNM is obligated to deliver 36 MW of power only when SJGS Unit 4 is operating.  These agreements are not considered derivatives because there is no notional amount due to the unit-contingent nature of the transactions. Therefore, these agreements are not recorded at fair value.

PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. TNMP does not enter into energy related derivative contracts.
Commodity Risk
Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative

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)


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.fluctuations. PNM monitors the market risk of its commodity contracts 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, PNM accounts for its various instruments for the purchase and sale of energy, which meet the definition of a derivative, based on PNM’s intent. During the ninesix months ended SeptemberJune 30, 20172018 and the year ended December 31, 2016,2017, PNM was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The derivative 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

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


derivative 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. PNM has no trading transactions.

Commodity Derivatives

PNM’s commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows:
Economic HedgesEconomic Hedges
September 30,
2017		 December 31,
2016		June 30,
2018		 December 31,
2017
(In thousands)(In thousands)
Current assets$3,093
 $5,224
$1,094
 $1,088
Deferred charges3,846
 —
3,014
 3,556
6,939
 5,224
4,108
 4,644
Current liabilities(1,279) (2,339)(1,416) (1,182)
Long-term liabilities(3,846) —
(3,014) (3,556)
(5,125) (2,339)(4,430) (4,738)
Net$1,814
 $2,885
$(322) $(94)

Included in the above table are $0.7 million and $2.7 million of current assets at September 30, 2017 and December 31, 2016 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. PNM does not offset fair value and cash collateral for derivative instruments under master netting arrangements and the above table reflects the gross amounts of fair value assets and liabilities for commodity derivatives. Included in the above table are equal amounts of assets and liabilities aggregating $4.9$4.1 million at SeptemberJune 30, 20172018 and $0.5$4.6 million at December 31, 2016,2017, which result from PNM’s hazard sharing arrangements with Tri-State (Note 12).Tri-State. The hazard sharing arrangements are net-settled upon delivery. Other amounts that could be offset under master netting agreements were immaterial.

At SeptemberJune 30, 20172018 and December 31, 20162017, PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at SeptemberJune 30, 20172018 and December 31, 20162017, amounts posted as cash collateral under margin arrangements were $1.20.5 million and $2.60.8 million. At June 30, 2018 and December 31, 2017, obligations to return cash collateral were $1.9 million and $0.9 million. Cash collateral amounts are included in other current assets and other current liabilities on the Condensed Consolidated Balance Sheets.

PNM has a NMPRC-approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes less than $0.1 million ofin current assets and $0.2$0.3 million of current liabilities at SeptemberJune 30, 20172018 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. There were no amounts hedged under this plan as of December 31, 2017.

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


and $0.2 million of current assets and $0.1 million of current liabilities at December 31, 2016 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.
The following table presents the effect of mark-to-market commodity derivative instruments on PNM’s earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.
Economic HedgesEconomic Hedges
Three Months Ended Nine Months EndedThree Months Ended Six Months Ended
September 30, September 30,June 30, June 30,
2017 2016 2017 20162018 2017 2018 2017
(In thousands)(In thousands)
Electric operating revenues$(2,237) $1,652
 $5,697
 $214
$8
 $4,592
 $(2) $7,933
Cost of energy(14) (1) (5,289) (1,113)(8) (5,286) 4
 (5,276)
Total gain (loss)$(2,251) $1,651
 $408
 $(899)
Total gain$—
 $(694) $2
 $2,657
Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNM’s net buy (sell) volume positions:
  Economic Hedges
  MMBTU MWh
     
September 30, 2017 100,000
 (630,933)
December 31, 2016 254,100
 (2,471,600)
  Economic Hedges
  MMBTU MWh
     
June 30, 2018 330,000
 (51,200)
December 31, 2017 100,000
 —
PNM has 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. In connection with managing its commodity risks, PNM enters into master agreements with certain counterparties. If PNM is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral if PNM’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that PNM will perform; and others have no provision for collateral. At SeptemberJune 30, 20172018 and December 31, 2016,2017, PNM had no$0.2 million and zero of such contracts in a net liability position.

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. PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers beginning on January 1, 2018. As of September 30, 2017, PNM had contracted to sell substantially all 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 for substantially all of the sales through 2017, which average approximately $29 per MWh.

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-saleInvestment securities are carried at fair value. Available-for-saleInvestment securities consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and trusts for PNM’s share of final reclamation costs related to the coal mines serving SJGS and Four Corners (Note 11). At SeptemberJune 30, 20172018 and December 31, 2016,2017, the fair value of available-for-saleinvestment securities included $283.0$292.8 million and $253.9$293.7 million for the NDT and $23.4$30.3 million and $19.1$29.8 million for the mine reclamation trusts. The

In January 2016, the FASB issued Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10), which makes targeted improvements to GAAP regarding financial instruments. ASU 2016-01 eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and requires those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. Under ASU 2016-01, the accounting for available-for-sale debt securities remains essentially unchanged. The accounting required by ASU 2016-01 is to be applied prospectively with a cumulative effect adjustment recorded as of the beginning of the year of adoption. ASU 2016-01 also revises certain presentation and grossdisclosure requirements. Accordingly, the following information for 2018 is presented under ASU 2016-01 and the information for 2017 is presented under prior GAAP.

Prior to 2018, PNM classified all debt and equity investments held in the NDT and coal mine reclamation trusts as available-for-sale securities. Unrealized losses on these securities were recorded immediately through earnings and unrealized gains were recorded in AOCI until the securities were sold.

On January 1, 2018, PNM recorded an after-tax cumulative effect adjustment of investments in available-for-sale$11.2 million to reclassify unrealized holding gains on equity securities are presentedheld in the following table.NDT and coal mine reclamation trusts from AOCI to retained earnings on the

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)


Condensed Consolidated Balance Sheets. After January 1, 2018, all gains and losses resulting from sales and changes in the fair value of equity securities are recognized in earnings.

Gains and losses recognized on the Condensed Consolidated Statements of Earnings related to investment securities in the NDT and reclamation trusts are presented in the following table.
 September 30, 2017 December 31, 2016
 Unrealized Gains Fair Value Unrealized Gains Fair Value
   (In thousands)  
Cash and cash equivalents$—
 $8,151
 $—
 $23,683
Equity securities:       
   Domestic value5,252
 72,162
 1,135
 34,796
   Domestic growth5,775
 73,345
 3,032
 47,595
International and other4,865
 43,167
 2,029
 27,481
Fixed income securities:       
   U.S. Government307
 28,960
 115
 40,962
   Municipals998
 41,131
 585
 43,789
   Corporate and other1,434
 39,528
 553
 54,671
 $18,631
 $306,444
 $7,449
 $272,977
  
Three Months Ended
June 30, 2018
 
Six Months Ended
June 30, 2018
  (In thousands)
Equity securities:    
Net gains from equity securities sold $2,502
 $5,330
Net gains (losses) from equity securities still held (443) (307)
Total net gains on equity securities 2,059
 5,023
Available-for-sale debt securities:    
Net gains (losses) on debt securities (3,729) (6,405)
Net gains (losses) on investment securities $(1,670) $(1,382)

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities held in the NDT and coal mine reclamation trusts 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 (increase)/decrease in realized impairment losses of $0.1$(2.6) million and $1.1$(3.8) million for the three and ninesix months ended SeptemberJune 30, 20172018 and $0.1$(0.1) million and $1.0 million for the three and ninesix months ended SeptemberJune 30, 2016.2017.
Three Months Ended Nine Months EndedThree Months Ended Six Months Ended
September 30, September 30,June 30, June 30,
2017 2016 2017 20162018 2017 2018 2017
(In thousands)(In thousands)
Proceeds from sales$98,532
 $86,975
 $456,577
 $280,989
$167,359
 $91,657
 $794,088
 $358,045
Gross realized gains$8,128
 $7,026
 $24,745
 $27,273
$7,549
 $7,971
 $13,570
 $16,617
Gross realized (losses)$(2,829) $(2,565) $(8,150) $(12,913)$(6,192) $(2,236) $(10,869) $(5,321)
Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. At September 30, 2017 and December 31, 2016,2017, PNMR’s held-to-maturity debt securities consistconsisted of the Westmoreland Loan. In May 2018, the full amount owed under the Westmoreland Loan was repaid (Note 11).

The Company has no available-for-sale or held-to-maturitydebt securities for which carrying value exceeds fair value. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings.
At June 30, 2018, the available-for-sale debt securities held by PNM, had the following final maturities:
 Fair Value
 (In thousands)
Within 1 year$8,883
After 1 year through 5 years61,875
After 5 years through 10 years67,445
After 10 years through 15 years10,102
After 15 years through 20 years9,574
After 20 years43,241
 $201,120


PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


At September 30, 2017, 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
 (In thousands)
Within 1 year$3,913
 $—
After 1 year through 5 years22,766
 76,353
After 5 years through 10 years25,456
 —
After 10 years through 15 years5,178
 —
After 15 years through 20 years10,692
 —
After 20 years41,614
 —
 $109,619
 $76,353

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 ninesix months ended SeptemberJune 30, 20172018 or the year ended December 31, 2016.2017.

For available-for-saleinvestment securities, Level 2 and Level 3 fair values are provided by the trusteefund managers utilizing a pricing service. TheFor Level 2 fair values, 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. Fair values of Level 2 investments in mutual funds are equal to net asset value as of year-end. Level 3 investments are comprised of corporate term loans. 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 asThe valuation of Level 3 primarilyinvestments requires significant judgment by the pricing provider due to the absence of quoted market values, changes in market conditions, and the long-term nature of the assets. The significant unobservable inputs include the trading multiples of public companies that are considered comparable to the company being valued, company specific issues, estimates of liquidation value, current operating performance and future expectations of performance, changes in market outlook and the financing environment, capitalization rates, discount rates, and cash flows. For the Westmoreland Loan, fair values were determined byusing an internal valuation model of discounted cash flow modelsflows that taketook into consideration discount rates that are observable for similar types of assets and liabilities. Management of the Company independently verifies the information provided by pricing services.

Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy along with gross unrealized gains on investments in available-for-sale securities. Under ASU 2016-01, PNM does not classify its investments in equity instruments as available-for-sale securities beginning January 1, 2018.

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 by PNM 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, 2017 and December 31, 2016 for items recorded at fair value.
  GAAP Fair Value Hierarchy  GAAP Fair Value Hierarchy  
Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2)Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) 
Significant Unobservable Inputs
(Level 3)
 Unrealized Gains
(In thousands)(In thousands)
September 30, 2017     
June 30, 2018         
Cash and cash equivalents$7,850
 $7,850
 $—
 $—
  
Equity securities:         
Corporate stocks, common35,363
 35,363
 —
 —
  
Corporate stocks, preferred6,338
 849
 5,489
 —
  
Mutual funds and other72,434
 72,434
 —
 —
  
Available-for-sale debt securities:         
U.S. Government29,621
 22,178
 7,443
 —
 $249
International Government8,757
 —
 8,757
 —
 4
Municipals43,493
 —
 43,493
 —
 157
Corporate and other119,249
 —
 116,258
 2,991
 565
$323,105
 $138,674
 $181,440
 $2,991
 $975
         
Commodity derivative assets$4,108
 $—
 $4,108
 $—
  
Commodity derivative liabilities(4,430) —
 (4,430) —
  
Net$(322) $—
 $(322) $—
  
         
December 31, 2017         
Available-for-sale securities     
        
Cash and cash equivalents$8,151
 $8,151
 $—
$52,636
 $52,636
 $—
 $—
  
Equity securities:     
        
Domestic value72,162
 72,162
 —
40,032
 40,032
 —
 —
 $4,011
Domestic growth73,345
 73,345
 —
35,456
 35,456
 —
 —
 3,995
International and other43,167
 39,931
 3,236
45,867
 42,332
 3,535
 —
 6,810
Fixed income securities:              
U.S. Government28,960
 28,273
 687
34,317
 33,645
 672
 —
 273
Municipals41,131
 —
 41,131
48,076
 —
 48,076
 —
 1,225
Corporate and other39,528
 —
 39,528
67,140
 —
 67,140
 —
 1,714
$306,444
 $221,862
 $84,582
$323,524
 $204,101
 $119,423
 $—
 $18,028
     
        
Commodity derivative assets$6,939
 $—
 $6,939
$4,644
 $—
 $4,644
 $—
  
Commodity derivative liabilities(5,125) —
 (5,125)(4,738) —
 (4,738) —
  
Net$1,814
 $—
 $1,814
$(94) $—
 $(94) $—
  
     
December 31, 2016     
Available-for-sale securities
    
Cash and cash equivalents$23,683
 $23,683
 $—
Equity securities:
    
Domestic value34,796
 34,796
 —
Domestic growth47,595
 47,595
 —
International and other27,481
 27,481
 —
Fixed income securities:     
U.S. Government40,962
 39,723
 1,239
Municipals43,789
 —
 43,789
Corporate and other54,671
 23,158
 31,513
$272,977
 $196,436
 $76,541

    
Commodity derivative assets$5,224
 $—
 $5,224
Commodity derivative liabilities(2,339) —
 (2,339)
Net$2,885
 $—
 $2,885


PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


A reconciliation of the changes in Level 3 fair value measurements is as follows:
 Corporate Debt
 (In thousands)
Balance at December 31, 2017$—
Actual return on assets sold during the period(4)
Actual return on assets still held at period end(5)
Purchases4,011
Sales(1,011)
Balance at June 30, 2018$2,991

The carrying amounts and fair values of investments in the Westmoreland Loan, 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    GAAP Fair Value Hierarchy
Carrying Amount Fair Value Level 1 Level 2 Level 3Carrying Amount Fair Value Level 1 Level 2 Level 3
September 30, 2017(In thousands)
June 30, 2018(In thousands)
PNMR         
Long-term debt$2,594,042
 $2,643,276
 $—
 $2,643,276
 $—
Other investments$373
 $373
 $373
 $—
 $—
PNM         
Long-term debt$1,655,760
 $1,679,090
 $—
 $1,679,090
 $—
Other investments$153
 $153
 $153
 $—
 $—
TNMP         
Long-term debt$540,327
 $566,327
 $—
 $566,327
 $—
Other investments$220
 $220
 $220
 $—
 $—
         
December 31, 2017         
PNMR                  
Long-term debt$2,447,702
 $2,564,887
 $—
 $2,564,887
 $—
$2,437,645
 $2,554,836
 $—
 $2,554,836
 $—
Westmoreland Loan$66,230
 $76,353
 $—
 $—
 $76,353
$56,640
 $66,588
 $—
 $—
 $66,588
Other investments$386
 $386
 $386
 $—
 $—
$503
 $503
 $503
 $—
 $—
PNM                  
Long-term debt$1,657,396
 $1,736,026
 $—
 $1,736,026
 $—
$1,657,910
 $1,727,135
 $—
 $1,727,135
 $—
Other investments$166
 $166
 $166
 $—
 $—
$283
 $283
 $283
 $—
 $—
TNMP                  
Long-term debt$480,589
 $517,977
 $—
 $517,977
 $—
$480,620
 $527,563
 $—
 $527,563
 $—
Other investments$220
 $220
 $220
 $—
 $—
$220
 $220
 $220
 $—
 $—
         
December 31, 2016         
PNMR         
Long-term debt$2,392,712
 $2,540,693
 $—
 $2,540,693
 $—
Westmoreland Loan$95,000
 $100,893
 $—
 $—
 $100,893
Other investments$547
 $1,164
 $547
 $—
 $617
PNM         
Long-term debt$1,631,369
 $1,730,157
 $—
 $1,730,157
 $—
Other investments$316
 $316
 $316
 $—
 $—
TNMP         
Long-term debt$420,875
 $468,329
 $—
 $468,329
 $—
Other investments$231
 $231
 $231
 $—
 $—

(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, theThe Company changed its approach to awarding stock-based compensation. As a result, nohas not awarded stock options have been granted since 2010 and awards of restricted stock have increased.2010. 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 20162017 Annual Reports on Form 10-K.


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)


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 to employees vest ratably over three years from the grant date of the award. However, 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. Beginning with 2017 awards, the vesting period for awardsAwards of restricted stock to non-employee members of the Board isare expensed over a one year.year vesting period.

The stock-based compensation expense related to restricted stock awards without performance or market conditions to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for other such awards is amortized to compensation expense over the shorter of the requisite vesting period or the period until the participant becomes retirement eligible. Compensation expense for performance-based shares is recognized ratably over the performance period as required service is provided and is adjusted periodically to reflect the level of achievement expected to be attained.

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Compensation expense 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 SeptemberJune 30, 20172018 and December 31, 20162017, PNMR had unrecognized expense related to stock awards of $4.85.4 million and $4.53.8 million, which are expected to be recognized over an average of 2.01.79 and 1.81.53 years.

PNMR receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options, and a tax deduction for the value of restricted stock at the vesting date.
The FASB issued Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting to simplify several aspects of the accounting for share-based payment transactions and eliminate diversity in practice. PNMR’s historical accounting for stock compensation complies with ASU 2016-09, except for the treatment of the income tax consequences of awards and the presentation of reductions to taxes payable on the Consolidated Statements of Cash Flows. Prior to ASU 2016-09, benefits resulting from income tax deductions in excess of compensation cost recognized under GAAP for vested restricted stock and on exercised stock options (collectively, “excess tax benefits”) were recorded to equity provided the excess tax benefits reduced income taxes payable. Deficiencies resulting from tax deductions related to stock awards that were below recognized compensation cost upon vesting and on canceled stock options were recorded to equity. PNMR had not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. ASU 2016-09 requires that all excess tax benefits and deficiencies be recorded to tax expense and, when used to reduce income taxes payable, classified as cash flows from operating activities. PNMR adopted ASU 2016-09 as of January 1, 2017 and recorded excess tax benefits of $0.2 million and $2.3 million in the three and nine months ended September 30, 2017 of which $0.1 million and $1.7 million was allocated to PNM and $0.1 million and $0.6 million was allocated to TNMP. As required by ASU 2016-09, PNMR recorded the excess tax benefits that were not recognized in prior years, due to its net operating loss position, as a cumulative effect adjustment of $10.4 million on January 1, 2017, increasing retained earnings and decreasing accumulated deferred income taxes on the Condensed Consolidated Balance Sheets. When excess tax benefits are used to reduce income taxes payable, the benefit will be reflected in cash flows from operating activities.

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

The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:
 Nine Months Ended September 30, Six Months Ended June 30,
Restricted Shares and Performance Based Shares 2017 2016 2018 2017
Expected quarterly dividends per share $0.2425
 $0.2200
 $0.2650
 $0.2425
Risk-free interest rate 1.50% 0.94% 2.38% 1.50%
        
Market-Based Shares        
Dividend yield 2.67% 2.74% 2.96% 2.67%
Expected volatility 20.80% 20.44% 19.12% 20.80%
Risk-free interest rate 1.54% 0.97% 2.36% 1.54%


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 table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the ninesix months ended SeptemberJune 30, 20172018:
Restricted Stock Stock OptionsRestricted Stock Stock Options
Shares 
Weighted-
Average
Grant Date Fair Value
 Shares 
Weighted-
Average
Exercise Price
Shares 
Weighted-
Average
Grant Date Fair Value
 Shares 
Weighted-
Average
Exercise Price
Outstanding at December 31, 2016218,316
 $27.59
 305,874
 $12.29
Outstanding at December 31, 2017189,045
 $31.11
 193,441
 $9.98
Granted248,271
 $23.06
 —
 $—
221,062
 $29.65
 —
 $—
Exercised(270,855) $20.92
 (109,433) $15.89
(231,735) $28.37
 (107,941) $8.56
Forfeited(4,012) $29.96
 —
 $—
(3,562) $30.58
 —
 $—
Expired—
 $—
 (3,000) $30.50
—
 $—
 —
 $—
Outstanding at September 30, 2017191,720
 $31.10
 193,441
 $9.98
Outstanding at June 30, 2018174,810
 $32.90
 85,500
 $11.77

PNMR’s stock-based compensation program provides for performance and market targets through 2019.2020. Included as granted and as exercised in the above table are 49,68297,697 previously awarded shares that were earned for the 20142015 through 20162017 performance measurement period and ratified by the Board in February 20172018 (based upon achieving market targets at “target” levels, weighted at 60%, and not meeting performance targets at below “target” levels, weighted at 40%). Excluded from the above table are maximums of 138,081, 163,712, 137,036135,818, and 133,632152,750 shares for the three-year performance periods ending in 2017, 2018, 2019, and 20192020 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 was to receive 135,000 shares of PNMR’s common stock if PNMR met specific market targets at the end of 2016 and she remained an employee of the Company. Under the agreement, she received 35,000 of the total shares in 2015 since PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2016 and the Board ratified her receiving the remaining 100,000 shares, which are included in the above table, in February 2017. The retention award was made under the PEP and was approved by the Board on February 28, 2012.

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 meetsmet specific performance targets at the end of 2016 and 2017 and he remainsremained an employee of the Company. If PNMR achieved the specificspecified performance target for the period from January 1, 2015 through December 31, 2016, he was to receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. The specified market target was achieved at the end of 2016 and the Board ratified him receiving $100,000 of PNMR common stock in February 2017 based on a market per share value of $36.30 on the grant date of March 3, 2017, or 2,754 shares, which are included in the above table.shares. Similarly, if PNMR achievesachieved the specificspecified performance target for the period from January 1, 2015 through December 31, 2017, he wouldwas to receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. The specified performance target was achieved at the end of 2017 and the Board ratified him receiving $275,000 of PNMR common stock in February 2018 based on the market value per share of $35.85 on the grant date of March 2, 2018, or 7,670 shares, which are included in the above table. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

In March 2015, the Company entered into an additionala 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 wouldwas to receive 17,953 of the total shares if PNMR achievesachieved specific performance targets at the end of 2017. The specified performance target was achieved at the end of 2017 and the Board ratified her receiving the 17,953 shares in February 2018, which are included in the above table. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include anythe restricted stock shares that remain unvested under this retention award agreement.     
At SeptemberJune 30, 20172018, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $5.92.3 million with a weighted-average remaining contract life of 1.81.5 years. At SeptemberJune 30, 20172018, no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date.


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 table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options:
 Nine Months Ended September 30, Six Months Ended June 30,
Restricted Stock 2017 2016 2018 2017
Weighted-average grant date fair value $23.06
 $26.49
 $29.65
 $23.06
Total fair value of restricted shares that vested (in thousands) $5,666
 $5,011
 $8,328
 $5,489
        
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) $2,234
 $1,208
 $2,968
 $1,699

(9)Financing

The Company’s financing strategy includes both short-term and long-term borrowings. The Company utilizes short-term revolving credit facilities, as well as cash flows from operations, to provide funds for both construction and operating expenditures. Depending on market and other conditions, the Company will periodically sell long-term debt or enter into term loan arrangements and use the proceeds to reduce borrowings under the revolving credit facilities or refinance other debt. Each of the Company’s revolving credit facilities and term loans containshas contained a single financial covenant, which requires the maintenance of a debt-to-capitaldebt-to-capitalization ratio of less than or equal to 65%, and generally also include customary covenants, events of default, cross default provisions, and change of control provisions. In July 2018, the PNMR Revolving Credit Facility, the PNMR 2016 One-Year Term Loan (as extended), the PNMR 2016 Two-Year Term Loan, and the PNMR Development Revolving Credit Facility were each amended such that PNMR is now required to maintain a debt-to-capitalization ratio of less than or equal to 70%. The debt-to-capitalization ratio requirement remains at less than or equal to 65% for PNM and TNMP agreements. 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. Additional information concerning financing activities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K.

Financing Activities

As discussed in Note 11, NM Capital, a wholly-owned subsidiary of PNMR, entered into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent, as of February 1, 2016. The BTMU Term Loan Agreement hashad a maturity date of February 1, 2021 and bearsbore interest at a rate based on LIBOR plus a customary spread, which aggregated 4.06% at September 30, 2017.spread. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. The BTMU Term Loan Agreement and the guaranty include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio of 65%, and customary events of default, a cross default provision, and a change of control provision consistent with PNMR’s other term loan agreements. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding of $125.0 million (the “Westmoreland Loan”) to a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance Westmoreland’s purchase of SJCC. See Note 6. The BTMU Term Loan Agreement requiresrequired that NM Capital utilize all amounts, less taxes and fees, it receivesreceived under the Westmoreland Loan to repay the BTMU Term Loan Agreement. TheOn May 22, 2018, the full principal balance outstanding under the Westmoreland Loan of $50.1 million was repaid. NM Capital used a portion of the proceeds to repay all remaining principal of $43.0 million owed under the BTMU Term Loan AgreementAgreement. These payments effectively terminated the loan agreements. In addition, PNMR’s guarantee of NM Capital’s obligations was $60.9 million at September 30, 2017. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $15.7 million on the BTMU Term Loan Agreement in the twelve months ended September 30, 2018.also effectively terminated.

On October 21, 2016, PNMR entered into letter of credit arrangements with JPMorgan Chase Bank, N.A. (the “JPM LOC Facility”) under which letters of credit aggregating $30.3 million were issued to facilitate the posting of reclamation bonds, which SJCC is required to post in connection with permits relating to the operation of the San Juan mine (Note 11).

At December 31, 2016,On July 28, 2017, PNM had $37.0entered into an agreement (the “PNM 2017 Senior Unsecured Note Agreement”) with institutional investors for the sale of $450.0 million aggregate principal amount of SUNs (the “PNM 2018 SUNs”) offered in private placement transactions. On May 14, 2018, PNM issued $350.0 million of outstanding PCRBs, which have a final maturitythe PNM 2018 SUNs under that agreement and used the proceeds to repay an equal amount of June 1, 2040, and $20.0 million of outstanding PCRBs which have a final maturity of June 1, 2042. These PCRBs were subject to mandatory tender for remarketingPNM’s 7.95% SUNs that matured on June 1, 2017 and were successfully remarketed on that date. The $37.0 million of PCRBs now bear interest at 2.125% andMay 15, 2018. On July 31, 2018 PNM issued the $20.0 million of PCRBs now bear interest at 2.45%. Both series are now subject to mandatory tender for remarketing on June 1, 2022.remaining

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)



On June 14, 2017, TNMP entered into an agreement (the “TNMP 2017 Bond Purchase Agreement”), which provided TNMP would issue $60.0$100.0 million aggregate principal amount of 3.22% first mortgage bonds, due 2027 (the “2017 Series A Bonds”) on or about August 25, 2017, subject to satisfaction of certain conditions. TNMP issued the 2017 Series A Bonds on August 24, 2017PNM 2018 SUNs and usedwill use the proceeds to reduce short-term and intercompany debt and for general corporate purposes.

On July 20, 2017, PNM entered into a $200.0 million term loan agreement (the “PNM 2017 Term Loan Agreement”) between PNM and JPMorgan Chase Bank, N.A., as lender and administrative agent, and U.S. Bank National Association, as lender. The PNM 2017 Term Loan Agreement bears interest at a variable rate and must be repaid on or before January 18, 2019. PNM used the proceeds of the PNM 2017 Term Loan Agreement to prepay without penalty the $175.0 million PNM 2016 Term Loan Agreement, which was to mature on November 17, 2017, and to reduce short-term borrowings. The PNM 2017 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum debt-to-capital ratio of 65%, and customary events of default, a cross default provision, and a change of control provision consistent with PNM’s other term loan agreements.

On July 28, 2017, PNM entered intorepay an agreement (the “PNM 2017 Senior Unsecured Note Agreement”) with institutional investors for the sale of $450.0 million aggregate principalequal amount of Senior Unsecured Notes (the “PNM 2018 SUNs”) offered in private placement transactions. Under thePNM’s 7.50% SUNs at their maturity on August 1, 2018. The PNM 2017 Senior Unsecured Note Agreement PNM has agreed to issue $350.0 million of the PNM 2018 SUNs on or about May 15, 2018 and $100.0 million of the PNM 2018 SUNs on or about August 1, 2018. The issuances of the PNM 2018 SUNs are subject to the satisfaction of customary conditions. PNM will use the gross proceeds from the PNM 2018 SUNs to repay $350.0 million of PNM’s 7.95% Senior Unsecured Notes that mature on May 15, 2018 and $100.0 million of PNM’s 7.50% Senior Unsecured Notes that mature on August 1, 2018. The terms of the PNM 2017 Senior Unsecured Note Agreement includeincludes customary covenants, including a covenant that requires the maintenance ofPNM to maintain a debt-to-capitaldebt-to-capitalization ratio of less than or equal to 65%, customary events of default, including a cross default provision, and covenants regarding parity of financial covenants, liens and guarantees with respect to PNM’s material credit facilities. In the event of a change of control, PNM will be required to offer to prepay the PNM 2018 SUNs at par. PNM will have the right to redeem any or all of the PNM 2018 SUNs prior to their respective maturities, subject to payment of a customary make-whole premium. In accordance with GAAP, aggregate borrowings of $450.0$100.0 million under PNM’s Senior Unsecured Notes7.95% SUNs due on May 15, 2018 and August 1, 2018, are reflected as being long-term in the Condensed Consolidated Balance Sheet at SeptemberJune 30, 20172018 since the PNM 2017 Senior Unsecured Note Agreement demonstrates PNM’s ability and intent to re-finance the aggregate $450.0$100.0 million Senior Unsecured NotesSUNs on a long-term basis. Information concerning the maturities and interest rates on the PNM 2018 SUNs to be issued in May 2018 and August 2018 is as follows:
       
Funding Maturity Principal Interest
Date Date Amount Rate
    (In millions)  
       
May 14, 2018 May 15, 2023 $55.0
 3.15%
May 14, 2018 May 15, 2025 104.0
 3.45%
May 14, 2018 May 15, 2028 88.0
 3.68%
May 14, 2018 May 15, 2033 38.0
 3.93%
May 14, 2018 May 15, 2038 45.0
 4.22%
May 14, 2018 May 15, 2048 20.0
 4.50%
    350.0
  
July 31, 2018 August 1, 2028 15.0
 3.78%
July 31, 2018 August 1, 2048 85.0
 4.60%
    100.0
  
    $450.0
  
Scheduled      
Funding Maturity Principal Interest
Date Date Amount Rate
    (In millions)  
       
May 15, 2018 May 15, 2023 $55.0
 3.15%
May 15, 2018 May 15, 2025 104.0
 3.45%
May 15, 2018 May 15, 2028 88.0
 3.68%
May 15, 2018 May 15, 2033 38.0
 3.93%
May 15, 2018 May 15, 2038 45.0
 4.22%
May 15, 2018 May 15, 2048 20.0
 4.50%
    350.0
  
August 1, 2018 August 1, 2028 15.0
 3.78%
August 1, 2018 August 1, 2048 85.0
 4.60%
    100.0
  
    $450.0
  
.

On September 25, 2017,March 9, 2018, PNMR issued $300.0 million aggregate principal amount of 3.250% SUNs (the “PNMR 2018 SUNs”), which mature on March 9, 2021. The proceeds from the TNMPoffering were used to repay the $150.0 million PNMR 2015 Term Loan Agreement, and to reduce borrowings under the PNMR Revolving Credit FacilityFacility.

On April 9, 2018, PNMR Development deposited $68.2 million with PNM related to potential transmission network interconnections, which is shown as a cash inflow from financing activities on PNM’s Condensed Consolidated Statements of Cash Flows. PNM used the deposit to repay intercompany borrowings. PNM is required to pay interest to PNMR Development to the extent work under the interconnections has not been performed. During the three months ended June 30, 2018, PNM recognized $0.7 million of interest expense under the agreement. At June 30, 2018, PNM’s remaining obligation under the interconnection agreement with PNMR Development of $68.2 million is reflected in other deferred credits on PNM’s Condensed Consolidated Balance Sheets. As required by GAAP, all intercompany transactions related to this deposit have been eliminated on PNMR’s Condensed Consolidated Financial Statements.

On June 28, 2018, TNMP entered into an agreement, under which TNMP issued $60.0 million aggregate principal amount of 3.85% first mortgage bonds, due 2028. On July 25, 2018, TNMP entered into a $20.0 million term loan agreement (the “TNMP 2018 Term Loan Agreement”) that bears interest at a variable rate, which was amended2.76% at July 25, 2018, and restatedhas a maturity of July 25, 2020. TNMP used the proceeds from these issuances to extend its maturity from September 18,repay short-term borrowings and for general corporate purposes.

At June 30, 2018, to September 23, 2022variable interest rates were 2.88% on the $100.0 million PNMR 2016 Two-Year Term Loan, which matures in December 2018, and to provide for two one-year extension options, subject to approval by a majority of2.83% on the lenders.$200.0 million PNM 2017 Term Loan Agreement, which matures in January 2019.


PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)




In March 2015, PNMR entered into a $150.0 million Term Loan Agreement (the “PNMR 2015 Term Loan Agreement”), which bears interest at a variable rate and must be repaid by March 9, 2018. In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 1.927%, subject to change if there is a change in PNMR’s credit rating, for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018. In 2017, PNMR entered into three separate four-year hedging agreements whereby it effectively established fixed interest rates of 1.926%, 1.823%, and 1.629%, plus customary spreads over LIBOR, subject to change if there is a change in PNMR’s credit rating, for three separate tranches, each of $50.0 million, of its variable rate debt. These hedge agreements are accounted for as cash flow hedges. The fair value of the hedge related to the PNMR 2015 Term Loan Agreement was a gain of $0.3 million at September 30, 2017 and is included in Other current assets on the Condensed Consolidated Balance Sheets and a loss of less than $0.1 million at December 31, 2016. At September 30, 2017, one of the remaining hedge agreements had a fair value gain of $0.1 million, which is included in Other current assets, and the other two had fair value losses aggregating $0.5 million, which are included in Other current liabilities, on the Condensed Consolidated Balance Sheets. The fair values were determined using Level 2 inputs under GAAP, including using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the agreement.

At September 30, 2017, variable interest rates were 2.14% on the $150.0 million PNMR 2015 Term Loan Agreement, 2.19% on the $100.0 million PNMR 2016 Two-Year Term Loan, and 1.97% on the $200.0 million PNM 2017 Term Loan Agreement.

Short-term Debt and Liquidity

Currently, the PNMR Revolving Credit Facility has a financing capacity of $300.0$300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. In November 2016,$400.0 million. PNMR and PNM have entered into agreements to extend the maturitymaturities of both facilities from October 31, 2020 to October 31, 2021.2022. However, one lender, whose current commitment is $10.0 million under the PNMR Revolving Credit Facility and $40.0 million under the PNM Revolving Credit Facility, did not agree to extend its commitments beyond October 31, 2020. Unless one or more of the other current lenders or a new lender assumes the commitments of the non-extending lender, the financing capacities will be reduced to $290.0 million for the PNMR Revolving Credit Facility and $360.0 million for the PNM Revolving Credit Facility from November 1, 2020 through October 31, 2021.2022. PNM also has the $40.0 million PNM 2017 New Mexico Credit Facility that expires on December 12, 2022. 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 Facilitybonds and matures on September 23, 2022. PNM also hasIn July 2018, the $50.0 million PNM New MexicoPNMR Revolving Credit Facility thatwas amended to provide for two one-year extension options, subject to approval by a majority of the lenders.

On February 26, 2018, PNMR Development entered into a revolving credit facility with Wells Fargo Bank, National Association, as lender, which allows PNMR Development to borrow up to $24.5 million on a revolving credit basis and also provides for the issuance of letters of credit. The facility expires on January 8, 2018. February 25, 2019, bears interest at a variable rate, and contains terms similar to the PNMR Revolving Credit Facility. PNMR has guaranteed the obligations of PNMR Development under the facility. PNMR Development uses the facility to finance its participation in NMRD and other activities.

Short-term debt outstanding consisted of:
 September 30, December 31, June 30, December 31,
Short-term Debt 2017 2016 2018 2017
 (In thousands) (In thousands)
PNM:        
PNM Revolving Credit Facility $—
 $35,000
 $23,600
 $39,800
PNM New Mexico Credit Facility —
 26,000
PNM 2017 New Mexico Credit Facility 10,000
 —
 33,600
 39,800
TNMP Revolving Credit Facility —
 —
 13,500
 —
PNMR:        
PNMR Revolving Credit Facility 166,500
 126,100
 111,000
 165,600
PNMR 2016 One-Year Term Loan 100,000
 100,000
PNMR 2016 One-Year Term Loan (as extended) 100,000
 100,000
PNMR Development Revolving Credit Facility 24,500
 —
 $266,500
 $287,100
 $282,600
 $305,400

At SeptemberJune 30, 2017,2018, the weighted average interest rate was 2.49%3.33% for the PNMR Revolving Credit Facility, 3.22% for the PNM Revolving Credit Facility, 3.22% for the PNM 2017 New Mexico Credit Facility, 2.84% for the TNMP Revolving Credit Facility, 3.05% for the PNMR Development Revolving Credit Facility, and 2.09%2.89% for the PNMR 2016 One-Year Term Loan which matures in December 2017.(as extended).

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $6.4$6.5 million, $2.5 million, and $0.1 million at SeptemberJune 30, 20172018 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of SeptemberJune 30, 2018 and December 31, 2017, PNM had $4.9 million and zero and TNMP had no$0.1 million and zero of intercompany borrowings from PNMR.

In 2017, PNMR entered into three separate four-year hedging agreements whereby it effectively established fixed interest rates of 1.926%, 1.823%, and 1.629%, plus customary spreads over LIBOR, subject to change if there is a change in PNMR’s credit rating, for three separate tranches, each of $50.0 million, of its variable rate debt. These hedge agreements are accounted for as cash flow hedges. These hedge agreements had fair value gains totaling $3.7 million at June 30, 2018 that is included in other deferred charges and $1.4 million at December 31, 2017 that is included in other current assets on the Condensed Consolidated

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)


Balance Sheets. The fair values were determined using Level 2 inputs under GAAP, including using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the agreement.

At October 20, 2017July 25, 2018, PNMR, PNM, TNMP, and TNMPPNMR Development had availability of $118.5182.5 million, $397.5388.7 million, $68.7 million, and $69.0 million of availabilitynone under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $50.0$30.0 million of availability under the PNM New Mexico Credit Facility. Total availability at October 20, 2017July 25, 2018, on a consolidated basis, was $635.0669.9 million for PNMR. As of October 20, 2017July 25, 2018, PNM and TNMP had no borrowings from PNMR under their intercompany loan agreements.agreements of $20.0 million and $3.5 million. At October 20, 2017July 25, 2018, PNMR, PNM, and TNMP had invested cash of $1.50.9 million, $50.5 million,none, and none.

As described above, PNM entered into the PNM 2017 Senior Unsecured Note Agreement on July 28, 2017 to issue $450.0under which PNM issued $100.0 million of the PNM 2018 SUNs on May 15,July 31, 2018 andto repay an equal amount of PNM’s 7.50% SUNs at their maturity on August 1, 2018, proceeds from which will be used to repay like amounts of2018. The $200.0 million PNM Senior Unsecured Notes maturing2017 Term Loan Agreement matures on those dates.January 18, 2019. PNM has no other long-term debt due through June 30, 2019. TNMP has $172.3 million of first mortgage bonds that are due in April 2019. The $100.0 million PNMR 2016 One-Year Term Loan (as extended) matures on December 31,14, 2018 and the $100.0 million PNMR 2016 Two-Year Term Loan matures on December 21, 2018. The $50.0$24.5 million PNM New MexicoPNMR Development Revolving Credit Facility expires in January 2018. PNMR has maturities and other repayments of short-term and long-term debt aggregating $265.7 million in the period from October 1, 2017 through September 30, 2018 and $102.3 million in the remainder of 2018, including anticipated repayments on the BTMU Term Loan Agreement. TNMP has no required principal payments on its long-term debt through 2018.February 25, 2019. Additional information on debt maturities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K.

(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. The periodic costs or income of the PNM Plans and TNMP Plans are included in regulated rates to the extent attributable to regulated operations. PNM and TNMP receive a regulated return on the amounts funded for pension and OPEB plans in excess of the periodic cost or income to the extent included in retail rates (a “prepaid pension asset”).

Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K. Annual net periodic benefit cost for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. See New Accounting Pronouncements in Note 1.

PNM Plans

The following tables presentIn March 2017, the componentsFASB issued Accounting Standards Update 2017-07 – Compensation - Retirement Benefits (Topic 715) to improve the presentation of net periodic pension and other postretirement benefit costs. Prior to ASU 2017-07, the PNM Plans’Company presented all of its net periodic benefit cost:
 Three Months Ended September 30,
 Pension Plan OPEB Plan Executive Retirement Program
 2017 2016 2017 2016 2017 2016
 (In thousands)
Components of Net Periodic Benefit Cost           
Service cost$—
 $—
 $24
 $35
 $—
 $—
Interest cost6,727
 7,577
 1,006
 1,087
 174
 203
Expected return on plan assets(8,451) (8,854) (1,308) (1,371) —
 —
Amortization of net (gain) loss4,001
 3,455
 921
 286
 78
 64
Amortization of prior service cost(241) (241) (416) (7) —
 —
Net periodic benefit cost$2,036
 $1,937
 $227
 $30
 $252
 $267
            
            
costs, net of amounts capitalized to construction and other accounts, as administrative and general expenses on its statements of earnings. ASU 2017-07 requires the service cost component of net benefit costs be presented in the same line item or items as employees’ compensation. The other components of net periodic benefit cost (the “non-service cost components”) are required to be presented separately from the service cost component and outside of operating income. ASU 2017-07 also limits capitalization of net periodic benefit costs to only the service cost component. ASU 2017-07 requires retrospective presentation of the service and non-service cost components of net periodic benefit costs in the income statement and prospective application regarding the capitalization of only the service cost component of net periodic benefit costs. The Company adopted ASU 2017-07 as of January 1, 2018, its required effective date. In accordance with the standard, the PNM and PNMR Condensed Consolidated Statements of Earnings reflect a reclassification from administrative and general expenses to other (deductions) for the non-service cost components of net periodic benefit costs in the amount of $2.1 million and $4.3 million, net of amounts capitalized prior to the adoption of the standard, in the three and six months ended June 30, 2017. The non-service components of TNMP’s net periodic benefit costs in 2017 were insignificant. The Company believes PNM and TNMP can continue to capitalize the non-service cost components of net periodic benefit costs as regulatory assets and liabilities to the extent attributable to regulated operations. During the three and six months ended June 30, 2018, PNM recorded $1.2 million and $2.1 million of non-service cost as other (deductions), which is net of $0.1 million and $0.3 million deferred as regulatory assets, and TNMP recorded $0.1 million and $0.3 million of non-service cost to other income, which is net of less than $0.1 million and $0.1 million deferred as regulatory liabilities.

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


PNM Plans

The following table presents the components of the PNM Plans’ net periodic benefit cost:
Nine Months Ended September 30,Three Months Ended June 30,
Pension Plan OPEB Plan Executive Retirement ProgramPension Plan OPEB Plan Executive Retirement Program
2017 2016 2017 2016 2017 20162018 2017 2018 2017 2018 2017
(In thousands)(In thousands)
Components of Net Periodic Benefit Cost                      
Service cost$—
 $—
 $72
 $105
 $—
 $—
$—
 $—
 $21
 $24
 $—
 $—
Interest cost20,181
 22,731
 3,019
 3,260
 523
 609
6,068
 6,727
 860
 1,006
 155
 174
Expected return on plan assets(25,352) (26,562) (3,923) (4,113) —
 —
(8,672) (8,451) (1,353) (1,308) —
 —
Amortization of net (gain) loss12,004
 10,365
 2,762
 858
 235
 192
4,087
 4,001
 588
 921
 90
 78
Amortization of prior service cost(724) (724) (1,248) (22) —
 —
(241) (241) (416) (416) —
 —
Net periodic benefit cost$6,109
 $5,810
 $682
 $88
 $758
 $801
$1,242
 $2,036
 $(300) $227
 $245
 $252
           
           
Six Months Ended June 30,
Pension Plan OPEB Plan Executive Retirement Program
2018 2017 2018 2017 2018 2017
(In thousands)
Components of Net Periodic Benefit Cost           
Service cost$—
 $—
 $41
 $48
 $—
 $—
Interest cost12,135
 13,454
 1,720
 2,013
 311
 349
Expected return on plan assets(17,343) (16,901) (2,707) (2,615) —
 —
Amortization of net (gain) loss8,174
 8,003
 1,177
 1,841
 179
 157
Amortization of prior service cost(483) (483) (832) (832) —
 —
Net periodic benefit cost$2,483
 $4,073
 $(601) $455
 $490
 $506

PNM did not make any contributions to its pension plan trust in the three and ninesix months ended SeptemberJune 30, 20172018 and 20162017 and does not anticipate making any contributions to the pension plan in 20172018-2021, but expects to contribute $5.5 million in 2022, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.1%4.0% to 4.9%5.1%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made no contributions to the OPEB trust in the three and ninesix months ended SeptemberJune 30, 20172018 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2016.2017. PNM does not expect to make any contributions to the OPEB trust in 2017-2021.2018-2022.  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$0.9 million in the three and ninesix months ended SeptemberJune 30, 20172018 and $0.4 million and $1.2$0.9 million in the three and ninesix months ended SeptemberJune 30, 20162017 and are expected to total $1.51.6 million during 20172018 and $5.8$5.7 million for 2018-2021.2019-2022.


PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


TNMP Plans

The following tables presenttable presents the components of the TNMP Plans’ net periodic benefit cost:
 Three Months Ended September 30,
 Pension Plan OPEB Plan Executive Retirement Program
 2017 2016 2017 2016 2017 2016
 (In thousands)
Components of Net Periodic Benefit Cost           
Service cost$—
 $—
 $36
 $46
 $—
 $—
Interest cost722
 826
 139
 169
 8
 10
Expected return on plan assets(945) (986) (114) (122) —
 —
Amortization of net (gain) loss231
 175
 (20) (10) 2
 1
Amortization of prior service cost—
 —
 —
 —
 —
 —
Net Periodic Benefit Cost$8
 $15
 $41
 $83
 $10
 $11
            

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)


Nine Months Ended September 30,Three Months Ended June 30,
Pension Plan OPEB Plan Executive Retirement ProgramPension Plan OPEB Plan Executive Retirement Program
2017 2016 2017 2016 2017 20162018 2017 2018 2017 2018 2017
(In thousands)(In thousands)
Components of Net Periodic Benefit Cost                      
Service cost$—
 $—
 $107
 $139
 $—
 $—
$—
 $—
 $33
 $36
 $—
 $—
Interest cost2,165
 2,478
 417
 508
 25
 30
656
 722
 119
 139
 7
 8
Expected return on plan assets(2,834) (2,957) (342) (367) —
 —
(991) (945) (135) (114) —
 —
Amortization of net (gain) loss692
 525
 (60) (30) 7
 1
272
 231
 (56) (20) 4
 2
Amortization of prior service cost—
 —
 —
 —
 —
 —
—
 —
 —
 —
 —
 —
Net Periodic Benefit Cost$23
 $46
 $122
 $250
 $32
 $31
$(63) $8
 $(39) $41
 $11
 $10
           
Six Months Ended June 30,
Pension Plan OPEB Plan Executive Retirement Program
2018 2017 2018 2017 2018 2017
(In thousands)
Components of Net Periodic Benefit Cost           
Service cost$—
 $—
 $67
 $72
 $—
 $—
Interest cost1,312
 1,443
 238
 278
 15
 17
Expected return on plan assets(1,981) (1,889) (271) (228) —
 —
Amortization of net (gain) loss544
 461
 (113) (40) 8
 4
Amortization of prior service cost—
 —
 —
 —
 —
 —
Net Periodic Benefit Cost$(125) $15
 $(79) $82
 $23
 $21

TNMP did not make any contributions to its pension plan trust in the three and ninesix months ended SeptemberJune 30, 20172018 and 20162017 and does not anticipate making any contributions in 20172018-2021,-2022, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.1%4.0% to 4.9%5.1%. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions of nonezero and $0.7$0.3 million to the OPEB trust in the three and ninesix months ended SeptemberJune 30, 20172018 and no contributionzero and $0.7 million in the three and ninesix months ended SeptemberJune 30, 2016.2017. TNMP does not expectexpects to make anyno additional contributions to the OPEB trust in 20172018 and expects to make contributions totaling $1.4 million for 2018-2021.2019-2022. 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 ninesix months ended SeptemberJune 30, 20172018 and 20162017 and are expected to total $0.1 million during 20172018 and $0.4 million in 2018-2021.2019-2022.

(11)Commitments and Contingencies

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

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)


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, theThe 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, or 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 20162017 Annual Reports on Form 10-K.


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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 DC 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. The lawsuits filed by APS alleged that damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high-level waste from PVNGS. In August 2014, APS and the DOE entered into a settlement agreement, which established a process for the payment of claims for costs incurred through December 31, 2016. The settlement agreement has been extended to December 31, 2019. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. PNM records estimated claims on a quarterly basis. The benefit from the claims is passed through to customers under the FPPAC to the extent applicable to NMPRC regulated operations.

PNM estimates that it will incur approximately $57.7 million (in 2016 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 nuclear fuel is consumed. At SeptemberJune 30, 20172018 and December 31, 2016,2017, PNM had a liability for interim storage costs of $12.112.4 million and $12.112.3 million included in other deferred credits.

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.

On June 8, 2012, the DC 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 DC 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 DC 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, which was issued in September 2013.
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. The NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the DC Circuit issued its June 2012 decision although PVNGS had not been involved in any licensing actions affected by that decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. On May 19, 2016, the NRC denied petitions filed by multiple petitioners to revise the August 2014 rule. The DC Circuit issued an order upholding the August 2014 rule on June 3, 2016 and denied a subsequent petition for rehearing on August 8, 2016.
In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged, in the DC Circuit, 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. On January 3, 2014, the

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DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval, as ordered by the DC Circuit. 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

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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. Theprogress by adopting a new SIP every ten years. In the first SIP 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 were required 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 iswas demonstrated that the emissions from these sources causecaused or contributecontributed to visibility impairment in any Class I area, then BART must behave been installed by the beginning of 2018. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions.

On January 10, 2017, EPA published in the Federal Register revisions to the regional haze rule to provide certain clarifications to reflect interpretations of the 1999 rule. EPA also provided a companion draft guidance document for public comment. The new rule shifteddelayed the due date for the next cycle of SIPs that are designed to cover the second compliance period from 2019 to 2028, changed2021, altered the planning process that states must employ in determining whether to impose “reasonable progress” emission reduction measures, and gave new authority to federal land managers to seek additional emission reduction measures outside of the states’ planning process. Finally, the rule made several procedural changes to the regional haze program, including changes to the schedule and process for states to file 5-year progress reports, and revised certain aspects of the visibility impairment provisions.reports. EPA’s finalnew rule was challenged by numerous parties. The DC Circuit has granted unopposed requests extendingOn January 19, 2018, EPA filed a motion to hold the deadlinecase in abeyance in light of several letters issued by EPA on January 17, 2018 to grant various petitions for briefing proposalsreconsideration of the 2017 rule revisions. On January 30, 2018, the court placed the case in abeyance and directed EPA to December 21, 2017.file status reports on 90-day intervals beginning April 30, 2018. Although EPA’s decision to revisit the rule is not a determination on the merits of the issues raised in those petitions, EPA is likely to propose and take comment on additional revisions to the regional haze rules in the near future. PNM is currently evaluating the potential impacts of this rule on SJGS.rule.

SJGS

BART Compliance – SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. Note 16 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K contains detailed information concerning the BART compliance process, including interactions with governmental agencies responsible for environmental oversight and the NMPRC approval process. In December 2015, PNM received NMPRC approval for the plan to comply with the EPA regional haze rule at SJGS. Under the approved plan, the installation of selective non-catalytic reduction technology (“SNCR”) was required on SJGS Units 1 and 4 which installation was completed in early 2016 and Units 2 and 3 are to bewere retired by the end ofin December 2017. In addition to the required SNCR equipment, the NSR permit, which was required to be obtained in order to install the SNCRs, specified that SJGS Units 1 and 4 be converted to balanced draft technology (“BDT”). PNM’s share of the total costs for SNCRs and BDT equipment was $77.7 million. See Note 12 for information concerning the NMPRC’s treatment of BDT in PNM’s NM 2015 Rate Case. Although operating costs will be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 have increased with the installation of SNCR and BDT equipment.
OnThe December 16, 2015 the NMPRC issued an order regarding SJGS. Asalso provided, in that order:among other things, that:

PNM will retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) by December 31, 2017 and recover, over 20 years, 50% of their undepreciated net book value at that date and earn a regulated return on those costs
PNM iswas granted a CCN to acquire an additional 132 MW in SJGS Unit 4 effective January 1, 2018 with an initial book value of zero, plus the costs of SNCR and other capital additions
PNM iswas granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equalas a jurisdictional resource to the book valueserve New Mexico customers beginning January 1, 2018
PNM was authorized to acquire 65 MW of SJGS Unit 4 as of December 31, 2017, including transmission assets associated with PVNGS Unit 3, (currently estimated to aggregate approximately $155 million)merchant plant
No later than December 31, 2018, and before entering into a binding agreement for post-2022 coal supply for SJGS, PNM will file its position and supporting testimony in a NMPRC case to determine the extent to which SJGS should continue

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serving PNM’s retail customers’ needs after mid-2022; all parties to the stipulation agree to support this case being decided within six monthsmid-2022 (see Other SJGS Matters below and Note 12)
PNM is 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 PNM’s ownership share of SJGS, PNM will acquire and retire one MWh of RECs or allowances that include a zero-CO2 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 is discussed in Note 12)
PNM will not recover approximately $20 million of other costs incurred in connection with CAA compliance
The NMPRC will issue a Notice of Proposed Dismissal in PNM’s 2014 IRP

At December 31, 2015, PNM recorded losses for regulatory disallowances and restructuring costs, aggregating $165.7 million, reflecting a $127.6 million regulatory disallowance to reflect the write-off of the 50% of the estimated December 31, 2017 net book value that will not be recovered, the other unrecoverable costs, and the $16.5 million increase in the estimated liability recorded for coal mine reclamation resulting from the new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”). The ultimate amount of the regulatory disallowance will be dependent on the actual December 31, 2017 net undepreciated book values of SJGS Units 2 and 3. Accordingly, the amount recorded will be adjusted to reflect changes to the December 31, 2017 net book values. Additional information about the CSA is discussed under Coal Supply below and in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K.

During 2016, PNM revised its estimates of the December 31, 2017 projected book value of SJGS Units 2 and 3 and the other unrecoverable costs, which resulted in a net expense of $3.7 million, including a $4.5 million expense related to a refinement of the estimated liability for coal mine reclamation from the new coal mine reclamation arrangement. PNM recorded an expense of $0.8 million during the three months ended March 31, 2016, an expense of $5.2 million in the three months ended September 30, 2016, and a reduction of expense of $2.3 million in the three months ended December 31, 2016, which are reflected in regulatory disallowances and restructuring costs on the Condensed Consolidated Statement of Earnings. In addition, PNMR Development recorded an expense of $0.6 million in the three months ended March 31, 2016 for costs it was obligated to reimburse the other SJGS participants under the restructuring arrangement, which is included in other deductions on the Condensed Consolidated Statement of Earnings. At September 30, 2017, the carrying value for PNM’s current ownership share of SJGS Units 2 and 3 is comprised of plant in service of $471.8 million and accumulated depreciation and amortization (including cost of removal) of $211.6 million for a net undepreciated book value of $260.2 million, offset by 50% (which equals $128.6 million) of the anticipated December 31, 2017 undepreciated net book value of SJGS Units 2 and 3 that will not be recovered, resulting in the net carrying value for SJGS Units 2 and 3 being $131.6 million at September 30, 2017.

On January 14, 2016, NEE filed a Noticenotice of Appealappeal with the NM Supreme Court of the NMPRC’s December 16, 2015 order. On July 22, 2016, NEE filed a brieforder alleging that the NMPRC’s decision violated New Mexico statutes and NMPRC regulations because PNM did not adequately consider replacement resources other than those proposed by PNM, the NMPRC did not require PNM to adequately address and mitigate ratepayer risk, the NMPRC unlawfully shifted the burden of proof, and the NMPRC’s decision was arbitrary and capricious.  Answer briefs refuting NEE’s claims were filed on November 2, 2016 by PNM, the NMPRC, and certain intervenors. Reply briefs were filed by NEE on January 9, 2017 and theThe parties presented oral argument to the court on January 25, 2017. The court hasOn March 5, 2018, the NM Supreme Court issued its opinion affirming the NMPRC’s December 2015 order, thereby denying NEE’s appeal. A request for rehearing of the NM Supreme Court’s decision was not rendered a decision onfiled by the appeal and therestatutory deadline. This matter is no required time frame for a decision. In addition, onnow concluded.

NEE Complaint – On March 31, 2016, NEE filed a complaint with the NMPRC against PNM regarding the financing provided by NM Capital to facilitate the sale of SJCC (seeSJCC. See Coal Supply below).below. The complaint alleges that PNM failed to comply

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with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. On January 31, 2018, NEE filed a motion asking the NMPRC to investigate whether PNM’s relationship with WSJ, in light of Westmoreland’s financial condition, could be harmful to PNM’s customers. PNM responded requesting the NMPRC deny the motion and that NEE’s prior complaint be dismissed. On May 23, 2018, PNM filed its response to the NMPRC staff’s comments requesting additional information about the financing and noting that the Westmoreland Loan was paid in full on May 22, 2018. NEE and NMPRC staff responded on July 16, 2018. NEE continues its request that the NMPRC investigate whether Westmoreland’s financial condition could adversely affect PNM’s customers. The NMPRC staff response requested that PNM provide certain additional information about the financing transactions and stated an order to show cause requested by NEE is not warranted. The NMPRC has taken no further action on this matter.NEE’s January 31, 2018 motion or March 31, 2016 complaint. PNM cannot currently predict the outcome of these matters.

SJGS Ownership Restructuring Matters – As discussed in Note 16 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K, SJGS currently iswas jointly owned by PNM and eight other entities. The SJPPA that governs the operation of SJGS expires on July 1, 2022. In connection with the

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proposed retirement of plan to comply with EPA regional haze rules at 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 negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items. The exiting participants currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4, but none of SJGS Units 1 and 2. PNM currently owns 50.0% of SJGS Units 1, 2, and 3 and owns 38.5% of SJGS Unit 4.

Following mediated negotiations,On July 31, 2015, the SJGS participants executed the San Juan Project Restructuring Agreement (“SJGS RA”) on July 31, 2015.. The SJGS RA provides the essential terms of restructured ownership and addresses other related matters, including that the exiting participants 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. PNMR Development became a party to the RA and agreed to acquire a 65 MW ownership interest inThe SJGS Unit 4 on the December 31, 2017 exit date, but has obligations related to Unit 4 before then. On the exit date, PNM would acquire 132 MW and PNMR Development would acquire 65 MW of the capacity in SJGS Unit 4 from the exiting owners for no initial cost other than funding capital improvements, including the costs of installing SNCR and BDT equipment. PNMR Development’s share of the costs of installing SNCR and BDT equipment amounted to $7.6 million. PNMR Development has assigned the rights and obligations related to the 65 MW to PNM effective on December 31, 2017, which will facilitate dispatch of power from that capacity. As ordered by the NMPRC, PNM will treat the 65 MW as merchant utility plant that will be excluded from retail rates. In anticipation of the transfer of ownership, PNM entered into agreements to sell the power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022 (Note 7). Reflecting the additions of the 132 MW and 65 MW, PNM’s ownership share would be 77.3% in SJGS Unit 4 and an aggregate of 66.3% in SJGS Units 1 and 4.

The RA became effective contemporaneously with the effectiveness of the new SJGS CSA. The effectiveness of the new SJGS CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which occurred on January 31, 2016 as discussed in Coal Supply below, occurred at 11:59 PM on January 31, 2016. The RA sets forth the terms under which PNM acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and is suppling coal to the exiting participants for the period from January 1, 2016 through December 31, 2017, which arrangement provides economic benefits that are being passed on to PNM’s customers through the FPPAC.below.

Other SJGS Matters – Although the SJGS RA results in an agreement among the SJGS participants enabling compliance with current CAA requirements, it is possible that the financial impact of climate change regulation or legislation, 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. PNM’s 2017 IRP (Note 12) filed with the NMPRC on July 3, 2017 presented resource portfolio plans for scenarios that assumed SJGS will operate beyond the end of the current coal supply agreement that runs through June 30, 2022 (see Coal Supply below) and for scenarios that assumed SJGS will cease operations after mid-2022. The 2017 IRP data shows that retiring SJGS in 2022 would provide long-term cost benefits to PNM’s customers.

The 2017 IRP is not a final determination of PNM’s future generation portfolio.  Retiring PNM’s share of SJGS would require PNM to make a formal abandonment filing with the NMPRC.  The final determination of PNM’s exit from SJGS would be subject to NMPRC review and approval.  PNM would also be required to obtain NMPRC approval of replacement power resources through formal CCN filings. The December 2015 NMPRC order discussed above authorized PNM to acquire 132 MW of SJGS Unit 4 as a New Mexico jurisdictional resource and 65 MW of SJGS Unit 4 as merchant plant. That order also provides that, if SJGS Unit 4 is abandoned with undepreciated investment on PNM’s books, PNM would not be allowed to recover the undepreciated investment of its 132 MW interest. PNM is currently depreciating all its investments in SJGS through 2053, the expected life approved by the NMPRC.  PNM’s undepreciated investment in SJGS at June 30, 2018 was $406.4 million, which includes interests in the 132 MW and the 65 MW of $20.5 million and $10.2 million.  In the event of an early retirement of SJGS, PNM would be exposed to loss of its undepreciated investments in the facility and other costs, including costs associated with coal mine reclamation discussed below, if recovery of these items is not approved by the NMPRC.  The financial impact of early retirement and the NMPRC approval process are influenced by factors outside of PNM’s control, including the economic impact of a potential SJGS abandonment on the area surrounding the plant and related mine, as well as overall political and economic conditions in New Mexico. Because of the uncertainty in obtaining the required approvals, PNM is unable to predict the outcome of this matter.


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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 1-31, 2, and 3 by January 1, 2014 and install SCRselective catalytic reduction technology (“SCR”) post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. Installation of SCRs on Four Corners Unit 5 was completed in March 2018 and the installation on Unit 4 was completed in June 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 lbs/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.
PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $89.2$89.5 million, including amounts incurred through SeptemberJune 30, 20172018 and PNM’s AFUDC. PNM is seeking recovery from its ratepayers of these costs in its NM 2016 Rate Case discussed inSee Note 17 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K and Note 12. PNM is unable to predict12 for a discussion of the ultimate outcometreatment of this matter.these costs in PNM’s NM 2016 Rate Case.


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The agreements governing the operation of Four Corners and its coal supply expire in 2031. The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of climate change regulation or legislation, other environmental regulations, and other business or regulatory considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

Four Corners Federal Agency Lawsuit – On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016.  The court granted an APS motion to intervene in the litigation on August 3, 2016. On September 15, 2016, NTEC, the current owner of the mine providing coal to Four Corners, filed a motion to intervene for the limited purpose of seeking dismissal of the lawsuit based on NTEC’s tribal sovereign immunity. On September 11, 2017, the court granted NTEC’s motion and dismissed the case with prejudice, terminating the proceedings. The environmental group plaintiffs have untilfiled a Notice of Appeal of the dismissed order in the United States Court of Appeals for the Ninth Circuit on November 13, 2017 to file an appeal of this dismissal order.9, 2017. PNM cannot predict whether the plaintiffs will appeal the order or whetherif such appeal if filed, will be successful.successful and, if it is successful, the outcome of further district court proceedings.

Carbon Dioxide Emissions
On August 3, 2015, EPA established final standards to limit CO2 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 DC Circuit.

The Clean Power Plan establishes state-by-state targetsCircuit to challenge both the Carbon Pollution Standards for carbon emissions reductionnew sources and establishes deadlines for states to submit initial plans to EPA by September 6, 2016, with a potential two-year extension, and final plans by 2018. The September 2016 deadline passed with no action and the 2018 deadline could be adjusted due to the stay of the Clean Power Plan issued byfor existing sources. Numerous parties also simultaneously filed motions to stay the US Supreme Court and pending litigation described below. 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 inClean Power Plan during 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-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.

litigation. On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan. On January 26, 2016,Plan, but 29 states and state agencies filed a petition tosuccessfully petitioned the US Supreme Court to reverse the DC Circuit’s decision andfor a stay, the implementation of the Clean Power Plan. Onwhich was granted on February 9, 2016, the US Supreme Court issued a 5-4 decision granting the stay pending judicial review of the rule by the DC Circuit.2016. The decision means the Clean Power Plan is not in effect and neither states nor sources are not obliged to comply with its requirements. TheWith the US Supreme Court stay in place, the DC Circuit heard oral arguments on September 27, 2016 in the case challenging the Clean Power Plan, but has not rendered a decision.

The proposed federal plan released concurrently with the Clean Power Plan is important to Four Corners and the Navajo Nation.  Since the Navajo Nation does not have primacy over its air quality program, EPA would be the regulatory authority responsible for implementingmerits of the Clean Power Plan on the Navajo Nation if the Clean Power Plan is sustained under the current administration.  In addition, the proposed rule recommends that EPA determine it is “necessary or appropriate” for EPA to regulate COSeptember 27, 2016 in front of a ten judge 2en banc emissions onpanel. However, before the Navajo Nation.  The comment period forDC Circuit could issue an opinion, the proposedTrump Administration asked that the case be held in abeyance while the rule closed on January 21, 2016.  APS and PNM filed separate comments with EPA on EPA’s draft plan and model trading rules, advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPAre-evaluated, which was to determine that it was not necessary or appropriate, the Clean Power Plan would not apply to the Navajo Nation, in which case, APS has indicated the Clean Power Plan would not have a material impact on Four Corners.  PNM is unable to predict the financial or operational impacts on Four Corners operations if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation.granted.


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On June 30, 2016, EPA published in the Federal Register the design details of its voluntary Clean Energy Incentive Program under the Clean Power Plan. Comments were due to EPA on November 1, 2016.

On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order puts forth two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is

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affordable, reliable, safe, secure, and clean.  The order directs the EPA Administrator to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the New Source Performance StandardsNSPS for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, and (4) the Legal Memorandum supporting the Clean Power Plan, and (5) the New Source Performance Standards for Oil & Natural Gas Sector.Plan. It also directs the EPA Administrator to notify the US Attorney General of his intent to review rules subject to pending litigation so that the US Attorney General may notify the court and, in his discretion, request that the court delay further litigation pending completion of the reviews. In connection with its review,response to the Executive Order, EPA filed a petition with the DC Circuit requesting that the court hold the consolidated cases challenging the Clean Power Plan be held in abeyance until 30 days after the conclusion of EPA’s review and any subsequent rulemaking. The DC Circuit issued an order to holdrulemaking, which was granted. In addition, the consolidated cases in abeyance.  The DC Circuit issued a similar order in connection with a motion filed by EPA to hold consolidated cases challenging the NSPS in abeyance. EPA also signed a Federal Register notice announcing that EPA is initiating its review of the Clean Power Plan and providing advance notice of forthcoming rulemaking proceedings.

On October 10, 2017, EPA issued a NOPR proposing to repeal the Clean Power Plan and filed its status report with the court requesting the case be held in abeyance until the completion of the rulemaking on the proposed repeal. The NOPR proposes a legal interpretation concluding that the Clean Power Plan exceeds EPA’s statutory authority. Under the proposed interpretation, Section 111(d) limits EPA’s authority to adopt performance standards to only those physical and operational changes that can be implemented within an individual source. Therefore, measures in the Clean Power Plan that would require power generators to change their energy portfolios by shifting generation from coal to gas and from fossil fuel to renewable energy exceed EPA’s statutory authority. The NOPR was published in the Federal Register on October 16, 2017 starting a 60-day public comment period.and comments were due by April 26, 2018. Any final rule will be subject to legal challenge and judicial review. In a separate but related action, on December 28, 2017, EPA also noted that it is still evaluating whether to adopt apublished the Advance Notice of Proposed Rulemaking for replacement rule to regulateof the Clean Power Plan. On December 18, 2017, EPA released an advanced NOPR addressing GHG fromguidelines for existing electric utility generating units and may issueunits. Comments to EPA’s new rule were due by February 26, 2018. On July 9, 2018, EPA submitted a proposed rulemakingrule titled “State Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units” to the United States Office of Management and Budget for interagency review.

The proposed federal plan released concurrently with the Clean Power Plan is important to Four Corners and the Navajo Nation. Since the Navajo Nation does not have primacy over its air quality program, EPA would be the regulatory authority responsible for implementing the Clean Power Plan on the Navajo Nation if the Clean Power Plan is ultimately sustained. In addition, the proposed rule recommended that EPA determine it is “necessary or appropriate” for EPA to regulate CO2 emissions on the Navajo Nation. The comment period for the proposed rule closed on January 21, 2016. APS and PNM filed separate comments with EPA on EPA’s draft plan and model trading rules, advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. PNM is unable to predict the financial or operational impacts on Four Corners operations if the Clean Power Plan is ultimately implemented as proposed and EPA determines that a replacement rule would be appropriate.federal plan is necessary or appropriate for the Navajo Nation.

PNM’s review of the CO2 emission reductions standards under the Clean Power Plan is ongoing and the assessment of its impacts will depend on the proposed repeal of the Clean Power Plan, future GHG reduction rulemaking, litigation of theany final rule, and other actions the Trump Administration is taking through judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance, if any.

National Ambient Air Quality Standards (“NAAQS”)
The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO2, ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO2 NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO2 and the 24-hour SO2 standard. New Mexico is in attainment for the 1-hour NOx NAAQS.

On April 18, 2018, EPA published the final rule to retain the current primary health-based NOx standards of which NO2 is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO2 standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018.

On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO2 NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO2 sources to identify maximum 1-hour SO2 concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO2 sources through ambient monitoring or modeling. This characterization willwould result in these areas being designated as attainment, nonattainment, or unclassified for compliance

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with the 1-hour SO2 NAAQS.  On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposesimposed deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO2 emissions. The settlement resultsresulted 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:required that: (1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; (2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule.  SJGS and Four Corners SO2 emissions are below the tonnagesthresholds set forth in (1) above. EPA regions sent

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letters to state environmental agencies explaining how EPA plans to implement the consent decree.  The letters outline the schedule that EPA expects states to follow in moving forward with new SO2 non-attainment designations. NMED did not receive a letter.

On August 11, 2015, EPA released the Data Requirements Rule for SO2, telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO2 NAAQS.  On June 3, 2016, NMED notified PNM that air quality modeling results indicated that SJGS was in compliance with the standard. In January 2017, NMED submitted their formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO2 standard. In July of each year,On June 27, 2018, NMED will submit ansubmitted the first annual report for SJGS as required by the Data Requirements Rule. The report recommends that no further modeling is warranted at this time due to EPA documenting annualdecreased SO2 emissions from SJGS and the associated compliance status.emissions.

On May 14, 2015, PNM received an amendment to its NSR air permit for SJGS, which reflects the revised state implementation plan for regional haze BART and requires the installation of SNCRs as described above. The revised permit also requires the reduction of SO2 emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO2, and particulate matter. These reductions will help SJGS meet the NAAQS for these constituents. The BDT equipment modifications were installed at the same time as the SNCRs, in order to most efficiently and cost effectively conduct construction activities at SJGS. See Regional Haze – SJGS above.

In January 2010,On May 29, 2018, EPA announced itreleased a proposed rule that would strengthenretain the 8-hour ozoneprimary health-based NAAQS for SOx. EPA is proposing to retain the current 1-hour standard by setting a new standard in a range of 60-70for SO2, which is 75 parts per billion (“ppb”). , based on the 3-year average of the 99th percentile of daily maximum 1-hour SO2 concentrations.  SO2 is the most prevalent SOx compound and is used as the indicator for the primary SOx NAAQS.

On October 1, 2015, EPA 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 NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas.

On November 10, 2015, EPA proposed a rule revising its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data is affected by events outside an area’s control. The proposed rule is timelyimportant in light of the new more stringent ozone NAAQS final rule since western states like New Mexico and Arizona are particularly subject to elevated background ozone transport from natural local sources, such as wildfires, and transported via winds from distant sources, such as the stratosphere or another region or country.

On February 25, 2016, EPA released guidance on area designations, which states used to determine their initial designation recommendations by October 1, 2016. EPA recommended that states and tribes use the three most recent years of quality assured monitoring data available (e.g., 2013 to 2015) to recommend designations. In their submittals, states and tribes were also able to use preliminary 2016 data. EPA was expected to release final designations of attainment/nonattainment for areas by October 1, 2017. On June 6, 2017, the EPA Administrator sent letters to state governors announcing that EPA was extending, by one year, the deadline for promulgating area designations. However, on August 2, 2017, the Trump Administration reversed the decision to extend the deadline to issue area designations, thereby requiring EPA to issue designations for ozone attainment areas by October 1, 2017. To date, the EPA has not issued such designations. By October 2018, NMED is required to submit an infrastructure SIP that provides the basic air quality management program to implement the revised ozone standard. These plans are generally due within 36 months from the date of designation and are expected to be submitted to EPA by October 1, 2020.

NMED published its 2015 Ozone NAAQS Designation Recommendation Report on September 2, 2016. In New Mexico, NMED is designating only a small area in southern Dona Ana County as non-attainment for ozone. NMED will have responsibility for bringing this nonattainmentnon-attainment area into compliance and will look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. According to NMED’s website, “If emissions from Mexico keep New Mexico from meeting the standards, the New Mexico area could remain nonattainmentnon-attainment but would not face more stringent requirements over time.”

On February 25, 2016, EPA released guidance on area designations for ozone, which states used to determine their initial designation recommendations by October 1, 2016. On June 6, 2017, the EPA Administrator sent letters to state governors announcing that EPA was extending, by one year, the deadline for promulgating area designations. However, on August 2, 2017, the Trump

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Administration reversed the decision to extend the deadline to issue area designations, thereby requiring EPA to issue designations for ozone attainment areas by October 1, 2017.

On November 6, 2017, EPA released a final rule establishing some, but not all, initial area designations.  In that final rule, San Juan County, New Mexico, where SJGS and Four Corners are located, is designated as attainment/unclassifiable. The only county in New Mexico designated as non-attainment is Dona Ana County.  On April 30, 2018, EPA completed additional area designations for the 2015 ozone standards. In a related matter, EPA published a final rule on March 9, 2018 establishing air quality thresholds that define the classifications assigned to all nonattainment areas for ozone NAAQS. The final rule also establishes the timing of attainment dates for each nonattainment area classification, which are marginal, moderate, serious, severe, or extreme. The rule became effective May 8, 2018.

NMED is required to submit an infrastructure and transport SIP that provides the basic air quality management program to implement the revised ozone standard. This plan is generally due within 36 months from the date the NAAQS is promulgated and is expected to be submitted to the EPA by October 1, 2018. State ozone attainment plans are generally due within five to six years from the date of the ozone NAAQS promulgation and are planned for submittal in 2020 and 2021.

PNM does not believe there will be material impacts to its facilities as a result of NMED’s nonattainment designation of the small area within Dona Ana County, but must wait on EPA’s ultimate approval, which was to have occurred by October 1, 2017.County. 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.


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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 challengeschallenged 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 allegesalleged 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 seekssought 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.

Of the fifteen claims for relief in the WEG Petition, two concerned SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. SJCC intervened in this matter. The court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United StatesNM District CourtCourt. In July 2016, OSM filed a Motion for Voluntary Remand to allow the District of New Mexico. In February 2016, venue for this matter was transferredagency to the United States District Court for the Western District of Texas. A stay in this matter expired on April 1, 2016 and was not renewed although the parties continued to engage in settlement negotiations.conduct a new environmental analysis. On August 31, 2016, the court entered an order remanding the matter to OSM for the completion of an EIS. The EIS is to be completed by August 31, 2019. The court ruled that mining operations may continue in the interim and the litigation will beis administratively closed. If OSM does not complete the EIS within the time frame provided, the court will order immediate vacatur of the mining plan at issue.  The scope of the EIS will be determined throughissue absent a public process and is expected to include cumulative and indirect effects of surrounding sources.further court order based on good cause shown. On March 22, 2017, OSM issued its Notice of Intent to initiate the public scoping process and prepare an EIS for the project. The Notice of Intent provided that, in addition to analyzing the environmental effects of the mining project, the EIS will also analyze the indirect effects of coal combustion at SJGS. The public comment period ended on May 8, 2017 and the EIS is now in the resource data submittal phase.phase was completed in November 2017. The draft EIS was made available in May 2018. Public comments were due on July 9, 2018. PNM cannot currently predict the outcome of this matter.
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

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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 court granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.
Cooling Water Intake Structures
EPA signed its final cooling water intake structures rule on May 16, 2014, which establishes national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The final rule was published on August 15, 2014 and became effective October 14, 2014.
The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting Best Technology Available (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system, which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority.

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The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is in discussionworking with EPA regarding this issue. However, PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS.
On May 23, 2018, several environmental groups sued EPA Region IX in the Ninth Circuit Court over EPA’s failure to timely reissue the Four Corners NPDES permit. The requirementspetitioners asked the court to issue a writ of mandamus compelling EPA Region IX to take final action on the pending NPDES permit by a reasonable date. EPA subsequently reissued the NPDES permit on June 12, 2018. The permit does not contain conditions related to Four Corners will be addressed inthe cooling water intake structure rule as EPA determined that the facility has achieved BTA for both impingement and entrainment by operating a subsequent NPDES permitting cycle that will determine APS’s costs to complyclosed-cycle recirculation system and no additional conditions are necessary. On July 16, 2018, several environmental groups filed a petition for review with the rule. PNMEPA’s Environmental Appeals Board concerning the reissued permit. The environmental groups alleged that the permit was reissued in contravention of several requirements under the Clean Water Act and does not expect such costscontain required provisions concerning certain revised effluent limitation guidelines, existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. The coalition is seeking to be material.have the permit remanded to EPA for revision to address these allegations. PNM cannot predict the outcome of this matter.

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 offered 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.  All proposed alternatives establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. 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. The final rule, which became effective on January 4, 2016, 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

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must be incorporated into plants’ NPDES permits. Each plant must comply between 2018 and 2023 depending on when it needs a new/new or revised NPDES permit.

On April 14, 2017, EPA filed a motion with the United States Court of Appeals for the Fifth Circuit relating to ongoing litigation of the 2016 Steam Electric Effluent Guidelines rule. EPA asked the court to hold all proceedings in the case in abeyance until August 12, 2017 while EPA reconsiders the rule. EPA also asked to be allowed to file a motion on August 12, 2017 to inform the court if EPA wishes to seek a remand of any provisions of the rule so that EPA may conduct further rulemaking, if appropriate. The motion referred to the notice signed by the EPA Administrator on April 12, 2017, which announced EPA’s intent to reconsider this rule, as well as EPA’s administrative stay of the compliance deadlines. On August 22, 2017, the court granted the government’s motion and the litigation is held in abeyance until EPA’s further rulemaking has concluded.

On September 18, 2017, EPA published the final rule for postponement of certain compliance dates, which have not yet passed for the Effluent Limitations Guidelines rule, consistent with the EPA’s decision to grant reconsideration of that rule. The final rule postponed the earliest date on which compliance with the effluent limitation guidelines for these waste streams would be required from November 1, 2018 until November 1, 2020.

Because SJGS is zero discharge for wastewater and is not required to hold a NPDES permit, it is expected that minimal 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. It is expected that minimal to no requirements will be imposed at Reeves.Reeves Station.

On April 14, 2017, EPA filed a motion withreissued an NPDES permit for Four Corners on June 12, 2018. EPA determined that the United States Court of Appeals forguidelines in the Fifth Circuit relating2015 rule are not applicable to ongoing litigationthis permit because the effective dates of the 2016 Steam Electric Effluent Guidelines rule. EPA asks the court to hold all proceedings in the case in abeyance until August 12, 2017 while EPA reconsiders the rule. EPA also asks to be allowed to file a motion on August 12, 2017 to inform the court if EPA wishes to seek a remand of any provisions of the2015 effluent guidelines rule so that EPA may conduct further rulemaking, if appropriate. The motion refers to the notice signed by the EPA Administrator on April 12, 2017, which announced EPA’s intent to reconsider this rule, as well as EPA’s administrative stay of the compliance deadlines. On August 22, 2017, the court granted the government’s motion and the litigation is held in abeyance until EPA’s further rulemaking has concluded. On September 18, 2017, EPA published the final rule for postponement of certain compliance dates that have not yet passed for the Effluent Limitations Guidelines rule, consistent with the EPA's decision to grant reconsideration of that rule.

On April 25, 2017, EPA published in the Federal Register a notice of postponement of certain compliance dates for the 2016 Steam Electric Effluent Guidelines rule, consistent with the EPA's decision to grant reconsideration of the rule. Specifically, the deadlines that will be postponed are the "best available technology" limitations and pretreatment standards for each of the following waste streams: fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater.

were extended. 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 drafttechniques, during the next NPDES permit is proposedrenewal for Four Corners, APS is uncertain whatwhich will be required to comply with the finalized effluent limitations.in 2023. See Cooling Water Intake Structures above. PNM is unable to predict the outcome of this matterthese matters or a range of the potential costs of compliance.

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

The Superfund Oversight Section of the NMED also 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. Results of tests conducted by NMED in April 2012 and April 2013 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. 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. However, 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.  Therefore, PNM has agreed to monitor nitrate levels in a limited number of wells under the terms of the renewed discharge permit for the former generating station. 


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Effective December 22, 2015, PNM and NMED entered into a memorandum of understanding to address changing groundwater quality conditions at the site. Under the memorandum, PNM will continue hydrocarbon investigation of the site under the supervision of NMED and qualified costs of the work will be eligible for payment through the New Mexico Corrective Action Fund (“CAF”), which is administered by the NMED Petroleum Storage Tank Bureau. Among other things, money in the CAF is available to NMED to make payments to or on behalf of owners and operators for corrective action taken in accordance with statutory and regulatory requirements to investigate, minimize, eliminate, or clean up a release. PNM’s work plan and cost estimates for specific groundwater investigation tasks were approved by the Petroleum Storage Tank Bureau. PNM submitted a monitoring plan consisting of a compilation of the data associated with the recent monitoring activities conducted under the CAF to NMED on October 3, 2016. PNM has completed all CAF-related work associated with the monitoring plan and has received NMED’s approval. Under the next phase, NMED will preparePNM’s contractor prepared a scope of work, for PNM’s review and concurrence, which PNM anticipates will includeand NMED approved, for the installation of additional monitoring wells as well asand additional sampling of certain existing monitoring wells at the site. These activities were completed in June 2018. A second work plan for the next phase of work, which will include the installation of 19 additional monitoring wells, was submitted to the NMED. Work is expected to be completed in early 2019. Qualified costs of this work are eligible for payment through the CAF.

PNM is unable to predict the outcome of these matters.
Coal Combustion Byproducts Waste DisposalFour Corners
CCBs consisting
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, 2, and 3 by January 1, 2014 and install selective catalytic reduction technology (“SCR”) post-combustion NOx controls on each of fly ash, bottom ash,Units 4 and gypsum generated5 by July 31, 2018. Installation of SCRs on Four Corners Unit 5 was completed in March 2018 and the installation on Unit 4 was completed in June 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 lbs/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.
PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $89.5 million, including amounts incurred through June 30, 2018 and PNM’s AFUDC. See Note 17 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and Note 12 for a discussion of the treatment of these costs in PNM’s NM 2016 Rate Case.

The agreements governing the operation of Four Corners and its coal supply expire in 2031. The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of climate change regulation or legislation, other environmental regulations, and other business or regulatory considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

Four Corners Federal Agency Lawsuit – On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016.  The court granted an APS motion to intervene in the litigation on August 3, 2016. On September 15, 2016, NTEC, the current owner of the mine providing coal to Four Corners, filed a motion to intervene for the limited purpose of seeking dismissal of the lawsuit based on NTEC’s tribal sovereign immunity. On September 11, 2017, the court granted NTEC’s motion and dismissed the case with prejudice, terminating the proceedings. The environmental group plaintiffs filed a Notice of Appeal of the dismissed order in the United States Court of Appeals for the Ninth Circuit on November 9, 2017. PNM cannot predict if such appeal will be successful and, if it is successful, the outcome of further district court proceedings.

Carbon Dioxide Emissions
On August 3, 2015, EPA established final standards to limit CO2 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 filed petitions for review in the DC Circuit to challenge both the Carbon Pollution Standards for new sources and the Clean Power Plan for existing sources. Numerous parties also simultaneously filed motions to stay the Clean Power Plan during the litigation. On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan, but 29 states and state agencies successfully petitioned the US Supreme Court for a stay, which was granted on February 9, 2016. The decision means the Clean Power Plan is not in effect and neither states nor sources are obliged to comply with its requirements. With the US Supreme Court stay in place, the DC Circuit heard oral arguments on the merits of the Clean Power Plan on September 27, 2016 in front of a ten judge en banc panel. However, before the DC Circuit could issue an opinion, the Trump Administration asked that the case be held in abeyance while the rule is re-evaluated, which was granted.

On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order puts forth two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is

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affordable, reliable, safe, secure, and clean.  The order directs the EPA Administrator to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the NSPS for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, and (4) the Legal Memorandum supporting the Clean Power Plan. It also directs the EPA Administrator to notify the US Attorney General of his intent to review rules subject to pending litigation so that the US Attorney General may notify the court and, in his discretion, request that the court delay further litigation pending completion of the reviews. In response to the Executive Order, EPA filed a petition with the DC Circuit requesting the cases challenging the Clean Power Plan be held in abeyance until 30 days after the conclusion of EPA’s review and any subsequent rulemaking, which was granted. In addition, the DC Circuit issued a similar order in connection with a motion filed by EPA to hold cases challenging the NSPS in abeyance.

On October 10, 2017, EPA issued a NOPR proposing to repeal the Clean Power Plan and filed its status report with the court requesting the case be held in abeyance until the completion of the rulemaking on the proposed repeal. The NOPR proposes a legal interpretation concluding that the Clean Power Plan exceeds EPA’s statutory authority. Under the proposed interpretation, Section 111(d) limits EPA’s authority to adopt performance standards to only those physical and operational changes that can be implemented within an individual source. Therefore, measures in the Clean Power Plan that would require power generators to change their energy portfolios by shifting generation from coal combustion at SJGS are currently disposed ofto gas and from fossil fuel to renewable energy exceed EPA’s statutory authority. The NOPR was published in the surface mine pits adjacentFederal Register on October 16, 2017 and comments were due by April 26, 2018. Any final rule will be subject to judicial review. In a separate but related action, on December 28, 2017, EPA published the Advance Notice of Proposed Rulemaking for replacement of the Clean Power Plan. On December 18, 2017, EPA released an advanced NOPR addressing GHG guidelines for existing electric utility generating units. Comments to EPA’s new rule were due by February 26, 2018. On July 9, 2018, EPA submitted a proposed rule titled “State Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units” to the plant. SJGSUnited States Office of Management and Budget for interagency review.

The proposed federal plan released concurrently with the Clean Power Plan is important to Four Corners and the Navajo Nation. Since the Navajo Nation does not operatehave primacy over its air quality program, EPA would be the regulatory authority responsible for implementing the Clean Power Plan on the Navajo Nation if the Clean Power Plan is ultimately sustained. In addition, the proposed rule recommended that EPA determine it is “necessary or appropriate” for EPA to regulate CO2 emissions on the Navajo Nation. The comment period for the proposed rule closed on January 21, 2016. APS and PNM filed separate comments with EPA on EPA’s draft plan and model trading rules, advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. PNM is unable to predict the financial or operational impacts on Four Corners operations if the Clean Power Plan is ultimately implemented as proposed and EPA determines that a federal plan is necessary or appropriate for the Navajo Nation.

PNM’s review of the CO2 emission reductions standards under the Clean Power Plan is ongoing and the assessment of its impacts will depend on the proposed repeal of the Clean Power Plan, future GHG reduction rulemaking, litigation of any CCB impoundmentsfinal rule, and other actions the Trump Administration is taking through judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or landfills. a range of the potential costs of compliance, if any.

National Ambient Air Quality Standards (“NAAQS”)
The NMMMD currently regulates placementCAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO2,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO2 NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO2 and the 24-hour SO2 standard. New Mexico is in attainment for the 1-hour NOx NAAQS.

On April 18, 2018, EPA published the final rule to retain the current primary health-based NOx standards of ashwhich NO2 is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO2 standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018.

On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO2 NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO2 sources to identify maximum 1-hour SO2 concentrations. This characterization would result in these areas being designated as attainment, nonattainment, or unclassified for compliance

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with the 1-hour SO2 NAAQS.  On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposed deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO2 emissions. The settlement resulted from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree required that: (1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; (2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule.  SJGS and Four Corners SO2 emissions are below the thresholds 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 SO2 non-attainment designations. NMED did not receive a letter.

On August 11, 2015, EPA released the Data Requirements Rule for SO2, telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO2 NAAQS.  On June 3, 2016, NMED notified PNM that air quality modeling results indicated that SJGS was in compliance with the standard. In January 2017, NMED submitted their formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO2 standard. On June 27, 2018, NMED submitted the first annual report for SJGS as required by the Data Requirements Rule. The report recommends that no further modeling is warranted at this time due to decreased SO2 emissions.

On May 14, 2015, PNM received an amendment to its NSR air permit for SJGS, which reflects the revised state implementation plan for regional haze BART and requires the installation of SNCRs as described above. The revised permit also requires the reduction of SO2 emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO2, and particulate matter. These reductions help SJGS meet the NAAQS for these constituents. The BDT equipment modifications were installed at the same time as the SNCRs, in order to most efficiently and cost effectively conduct construction activities at SJGS. See Regional Haze – SJGS above.

On May 29, 2018, EPA released a proposed rule that would retain the primary health-based NAAQS for SOx. EPA is proposing to retain the current 1-hour standard for SO2, which is 75 parts per billion (“ppb”), based on the 3-year average of the 99th percentile of daily maximum 1-hour SO2 concentrations.  SO2 is the most prevalent SOx compound and is used as the indicator for the primary SOx NAAQS.

On October 1, 2015, EPA 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 NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas.

On November 10, 2015, EPA proposed a rule revising its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data is affected by events outside an area’s control. The proposed rule is important in light of the new more stringent ozone NAAQS final rule since western states like New Mexico and Arizona are particularly subject to elevated background ozone transport from natural local sources, such as wildfires, and transported via winds from distant sources, such as the stratosphere or another region or country.

NMED published its 2015 Ozone NAAQS Designation Recommendation Report on September 2, 2016. In New Mexico, NMED is designating only a small area in southern Dona Ana County as non-attainment for ozone. NMED will have responsibility for bringing this non-attainment area into compliance and will look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. According to NMED’s website, “If emissions from Mexico keep New Mexico from meeting the standards, the New Mexico area could remain non-attainment but would not face more stringent requirements over time.”

On February 25, 2016, EPA released guidance on area designations for ozone, which states used to determine their initial designation recommendations by October 1, 2016. On June 6, 2017, the EPA Administrator sent letters to state governors announcing that EPA was extending, by one year, the deadline for promulgating area designations. However, on August 2, 2017, the Trump

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Administration reversed the decision to extend the deadline to issue area designations, thereby requiring EPA to issue designations for ozone attainment areas by October 1, 2017.

On November 6, 2017, EPA released a final rule establishing some, but not all, initial area designations.  In that final rule, San Juan County, New Mexico, where SJGS and Four Corners are located, is designated as attainment/unclassifiable. The only county in New Mexico designated as non-attainment is Dona Ana County.  On April 30, 2018, EPA completed additional area designations for the 2015 ozone standards. In a related matter, EPA published a final rule on March 9, 2018 establishing air quality thresholds that define the classifications assigned to all nonattainment areas for ozone NAAQS. The final rule also establishes the timing of attainment dates for each nonattainment area classification, which are marginal, moderate, serious, severe, or extreme. The rule became effective May 8, 2018.

NMED is required to submit an infrastructure and transport SIP that provides the basic air quality management program to implement the revised ozone standard. This plan is generally due within 36 months from the date the NAAQS is promulgated and is expected to be submitted to the EPA by October 1, 2018. State ozone attainment plans are generally due within five to six years from the date of the ozone NAAQS promulgation and are planned for submittal in 2020 and 2021.

PNM does not believe there will be material impacts to its facilities as a result of NMED’s nonattainment designation of the small area within Dona Ana County. 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.

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 challenged several unrelated mining plan modification approvals, which were each separately approved by OSM.  WEG alleged 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 sought 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.

Of the fifteen claims for relief in the WEG Petition, two concerned SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine with federal oversightarise from OSM administrative actions in 2008. SJCC intervened in this matter. The court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the NM District Court. In July 2016, OSM filed a Motion for Voluntary Remand to allow the agency to conduct a new environmental analysis. On August 31, 2016, the court entered an order remanding the matter to OSM for the completion of an EIS by August 31, 2019. The court ruled that mining operations may continue in the interim and the litigation is administratively closed. If OSM does not complete the EIS within the time frame provided, the court will order immediate vacatur of the mining plan at issue absent a further court order based on good cause shown. On March 22, 2017, OSM issued its Notice of Intent to initiate the public scoping process and prepare an EIS for the project. The Notice of Intent provided that, in addition to analyzing the environmental effects of the mining project, the EIS will also analyze the indirect effects of coal combustion at SJGS. The public comment period ended on May 8, 2017 and the EIS resource data submittal phase was completed in November 2017. The draft EIS was made available in May 2018. Public comments were due on July 9, 2018. PNM cannot currently predict the outcome of this matter.
Navajo Nation Environmental Issues
Four Corners is located on the Navajo Reservation and is held under an easement granted by the OSM. APS disposes of CCBs in ash pondsfederal 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 dry storage areaspesticide activities, including those activities that occur at Four Corners. Ash management atIn October 1995, the Four Corners is regulated by EPAparticipants 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 New Mexico State Engineer’s Office.Navajo Nation signed an agreement
In
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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 court 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 became effective October 14, 2014.
The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting Best Technology Available (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system, which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority.
The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is working with EPA regarding this issue. However, PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS.
On May 23, 2018, several environmental groups sued EPA Region IX in the Ninth Circuit Court over EPA’s failure to timely reissue the Four Corners NPDES permit. The petitioners asked the court to issue a writ of mandamus compelling EPA Region IX to take final action on the pending NPDES permit by a reasonable date. EPA subsequently reissued the NPDES permit on June 2010,12, 2018. The permit does not contain conditions related to the cooling water intake structure rule as EPA determined that the facility has achieved BTA for both impingement and entrainment by operating a closed-cycle recirculation system and no additional conditions are necessary. On July 16, 2018, several environmental groups filed a petition for review with the EPA’s Environmental Appeals Board concerning the reissued permit. The environmental groups alleged that the permit was reissued in contravention of several requirements under the Clean Water Act and does not contain required provisions concerning certain revised effluent limitation guidelines, existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. The coalition is seeking to have the permit remanded to EPA for revision to address these allegations. PNM cannot predict the outcome of this matter.

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 offered 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.  All proposed alternatives establish a proposed“zero discharge” effluent limit for all pollutants in fly ash transport water. 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. The final rule, which became effective on January 4, 2016, 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

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must be incorporated into plants’ NPDES permits. Each plant must comply between 2018 and 2023 depending on when it needs a new or revised NPDES permit.

On April 14, 2017, EPA filed a motion with the United States Court of Appeals for the Fifth Circuit relating to ongoing litigation of the 2016 Steam Electric Effluent Guidelines rule. EPA asked the court to hold all proceedings in the case in abeyance until August 12, 2017 while EPA reconsiders the rule. EPA also asked to be allowed to file a motion on August 12, 2017 to inform the court if EPA wishes to seek a remand of any provisions of the rule so that included two optionsEPA may conduct further rulemaking, if appropriate. The motion referred to the notice signed by the EPA Administrator on April 12, 2017, which announced EPA’s intent to reconsider this rule, as well as EPA’s administrative stay of the compliance deadlines. On August 22, 2017, the court granted the government’s motion and the litigation is held in abeyance until EPA’s further rulemaking has concluded.

On September 18, 2017, EPA published the final rule for postponement of certain compliance dates, which have not yet passed for the Effluent Limitations Guidelines rule, consistent with the EPA’s decision to grant reconsideration of that rule. The final rule postponed the earliest date on which compliance with the effluent limitation guidelines for these waste designationstreams would be required from November 1, 2018 until November 1, 2020.

Because SJGS is zero discharge for wastewater and is not required to hold a NPDES permit, it is expected that minimal 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. It is expected that minimal to no requirements will be imposed at Reeves Station.

EPA reissued an NPDES permit for Four Corners on June 12, 2018. EPA determined that the guidelines in the 2015 rule are not applicable to this permit because the effective dates of coal ash. One option wasthe 2015 effluent guidelines rule were extended. Four Corners may be required to regulate CCBschange equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques, during the next NPDES permit renewal for Four Corners, which will be in 2023. See Cooling Water Intake Structures above. PNM is unable to predict the outcome of these matters or a range of the potential costs of compliance.
Santa Fe Generating Station
PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a hazardous waste,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 also 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 would allow EPAstates that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. Results of tests conducted by NMED in April 2012 and April 2013 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to createthe 2013 data. As part of this effort, PNM also collected a comprehensive federal programsample of hydrocarbon product for waste management“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 disposalolder fuels, and the location of CCBs. The other option wasthe 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. However, it is possible that PNM’s prior activities to regulate CCBsremediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels.  Therefore, PNM has agreed to monitor nitrate levels in a non-hazardous waste, which would provide EPA withlimited number of wells under the authority to develop performance standardsterms of the renewed discharge permit for waste management facilities handling CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications.the former generating station. 


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OnEffective December 19, 2014, EPA issued its coal ash rule, including22, 2015, PNM and NMED entered into a non-hazardous waste determination for coal ash. Coal ashmemorandum of understanding to address changing groundwater quality conditions at the site. Under the memorandum, PNM will continue hydrocarbon investigation of the site under the supervision of NMED and qualified costs of the work will be regulated as a solid waste under Subtitle D of RCRA. The rule sets minimum criteriaeligible 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.

Becausepayment through the ruleNew Mexico Corrective Action Fund (“CAF”), which 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, with an effective date of October 19, 2015. Based upon the requirements of the final rule, PNM conducted a CCB assessment at SJGS and made minor modifications at the plant to ensure that there are no facilities which would be considered impoundments or landfills under the rule. PNM does not expect it to have a material impact on operations, financial position, or cash flows.

As indicated above, CCBs at Four Corners are currently disposed of in ash ponds and dry storage areas. Depending upon the results of groundwater monitoring requiredadministered by the CCB rule, Four Corners may be required to take corrective action. Initial monitoring at Four Corners is not yet complete, so expenditures related to potential corrective actions, if any, cannot be reasonably estimated at this time.

Pursuant to a June 24, 2016 order by the DC Circuit in litigation by industry and environmental groups challenging EPA’s CCB regulations, EPA is required to complete a rulemaking proceeding by June 2019 to address specific technical issues related to the handling of CCBs.  EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion.  Should EPA take final action adding boron to the list of groundwater constituents, corrective action may be required. Any resulting corrective action measures may increase costs of compliance with the CCB rule at coal-fired generating facilities.  At this time, PNM cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

On December 16, 2016, the Water Infrastructure Improvements for the Nation Act (the “WIIN Act”) was signed into law to address critical water infrastructure needs in the United States. The WIIN Act contains a number of provisions requiring EPA to modify the self-implementing provisions of the current CCB rules under Subtitle D.NMED Petroleum Storage Tank Bureau. Among other things, money in the WIIN Act providesCAF is available to NMED to make payments to or on behalf of owners and operators for corrective action taken in accordance with statutory and regulatory requirements to investigate, minimize, eliminate, or clean up a release. PNM’s work plan and cost estimates for specific groundwater investigation tasks were approved by the Petroleum Storage Tank Bureau. PNM submitted a monitoring plan consisting of a compilation of the data associated with monitoring activities conducted under the CAF to NMED on October 3, 2016. PNM completed all CAF-related work associated with the monitoring plan and received NMED’s approval. PNM’s contractor prepared a scope of work, which PNM and NMED approved, for the establishmentinstallation of stateadditional monitoring wells and EPA permit programsadditional sampling of certain existing monitoring wells at the site. These activities were completed in June 2018. A second work plan for CCBs, provides flexibilitythe next phase of work, which will include the installation of 19 additional monitoring wells, was submitted to the NMED. Work is expected to be completed in early 2019. Qualified costs of this work are eligible for states to incorporatepayment through the EPA final rule for CCBs or develop other criteria that are at least as protective as the EPA’s final rule, and requires EPA to approve state permit programs within 180 days of submission by the state for approval. As a result, the CCB rule is no longer self-implementing and there will either be a state or federal permit program. Subject to Congressional appropriated funding, EPA will implement the permit program in states that choose not to implement a program. Until permit programs are in effect, EPA has authority to directly enforce the self-implementing CCB rule. For facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation where Four Corners is located, EPA is required to develop a federal permit program regardless of appropriated funds. EPA has yet to undertake rulemaking proceedings to implement the CCB provisions of the WIIN Act. There is no time line for establishing either state or federal permitting programs. APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on tribal reservations, including Four Corners. CAF.

PNM is unable to predict when EPA will be issuing permits for Four Corners.

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCBs, which were premised in part on the provisions of the WIIN Act, on September 13, 2017, EPA agreed to evaluate whether to revise the CCB regulations. At this time, it is not clear whether the EPA will initiate further notice-and-comment rulemaking to revise the CCB rules or what aspects of the rules might be changed as a result of this process. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of the CCB regulations, the DC Circuit ordered EPA to file a list of federal regulatory provisions addressing CCBs that are or likely will be revised by November 15, 2017.

The CCB rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in the future and will likely be influenced by EPA’s rule. 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’sthese matters.

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operations, financial position, or cash flows. PNM would seek recovery from its ratepayers of all CCB costs that are ultimately incurred.
Other Commitments and Contingencies
Coal Supply
SJGS
The coal requirements for SJGS are supplied by SJCC. SJCC holds certain federal, state, and private coal leases. Through January 31, 2016, SJCC was a wholly-owned subsidiary of BHP and supplied processed coal for operation of SJGS under an underground coal sales agreement (“UG-CSA”) that was to expire on December 31, 2017. In addition to coal delivered to meet the current needs of SJGS, PNM prepaid SJCC for certain coal mined but not yet delivered to the plant site. At September 30, 2017 and December 31, 2016, prepayments for coal (including amounts purchased from the existing SJGS participants discussed below), which are included in other current assets, amounted to $31.9 million and $48.7 million. Additional information concerning the coal supply for SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K.
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 UG-CSA. On July 1, 2015, PNM and Westmoreland Coal Company (“Westmoreland”) entered into a new coal supply agreement (“CSA”), pursuant to which Westmoreland would supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland would provide CCB disposal and mine reclamation services for SJGS. Contemporaneous with the entry into the coal-related agreements, Westmoreland entered into a stock purchase agreement (the “Stock Purchase Agreement”) on July 1, 2015 to acquire all of the capital stock of SJCC. 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 became effective as of 11:59 PM on January 31, 2016, upon the closing under the Stock Purchase Agreement. 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 were assigned to SJCC. Westmoreland has guaranteed SJCC’s performance under the CSA.

Pricing under the CSA is primarily 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 has the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. In order to extend, PNM must give written notice of that intent by July 1, 2018 and the parties must agree to the terms of the extension by January 1, 2019. However, as discussed in Note 12, PNM’s 2017 IRP shows that retirement of PNM’s SJGS capacity in 2022 would be cost-effective for customers. If retirement of SJGS is approved by the NMPRC, there will be no need to extend the CSA.

The RA sets forth terms under which PNM acquired the coal inventory, including coal mined but not delivered, of the exiting SJGS participants as of January 1, 2016 and is supplying 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. Coal costs under the CSA are significantly less than under the previous 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 are passed through to PNM’s customers.

In support of the closing under the Stock Purchase Agreement and to facilitate PNM customer savings, NM Capital, a wholly-owned subsidiary of PNMR, provided funding of $125.0 million (the “Westmoreland Loan”) to Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland, to finance WSJ’s purchase of the stock of SJCC (including an insignificant affiliate) under the Stock Purchase Agreement. NM Capital was able to provide the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent. The BTMU Term Loan Agreement became effective as of February 1, 2016, matures on February 1, 2021, and bears interest at a rate based on LIBOR plus a customary spread. In connection

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with the BTMU Term Loan Agreement, PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. The balance outstanding under the BTMU Term Loan Agreement was $60.9 million at September 30, 2017.

The Westmoreland Loan is a $125.0 million loan agreement among NM Capital, as lender, WSJ, as borrower, SJCC and its affiliate, as guarantors, BTMU, as administrative agent, and MUFG Union Bank, N.A., as depository bank. The Westmoreland Loan became effective as of February 1, 2016, and matures on February 1, 2021. The interest rate on the Westmoreland Loan escalates over time and was initially a rate of 7.25% plus LIBOR. Such rate is 9.25% plus LIBOR for the period from February 1, 2017 through January 31, 2018. WSJ must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. In addition, the Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. At September 30, 2017, the amount outstanding under the Westmoreland Loan was $66.2 million. The next principal payment of $9.6 million plus interest of $1.8 million is due on November 1, 2017. As of October 20, 2017, $11.4 million was held in a SJCC restricted bank account that is to be used solely to service the Westmoreland Loan. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC and its affiliate. The Westmoreland Loan also includes customary representations and warranties, covenants, and events of default. There are no prepayment penalties.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds of $118.7 million with the NMMMD. In order to facilitate the posting of reclamation bonds by sureties on behalf of SJCC, PNMR entered into separate letter of credit arrangements with a bank under which letters of credit aggregating $30.3 million have been issued.

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, 2, and 3 by January 1, 2014 and install selective catalytic reduction technology (“SCR”) post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. Installation of SCRs on Four Corners Unit 5 was completed in March 2018 and the installation on Unit 4 was completed in June 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 lbs/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.
PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $89.5 million, including amounts incurred through June 30, 2018 and PNM’s AFUDC. See Note 17 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and Note 12 for a discussion of the treatment of these costs in PNM’s NM 2016 Rate Case.

The agreements governing the operation of Four Corners and its coal supply expire in 2031. The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of climate change regulation or legislation, other environmental regulations, and other business or regulatory considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

Four Corners Federal Agency Lawsuit – On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016.  The court granted an APS motion to intervene in the litigation on August 3, 2016. On September 15, 2016, NTEC, the current owner of the mine providing coal to Four Corners, filed a motion to intervene for the limited purpose of seeking dismissal of the lawsuit based on NTEC’s tribal sovereign immunity. On September 11, 2017, the court granted NTEC’s motion and dismissed the case with prejudice, terminating the proceedings. The environmental group plaintiffs filed a Notice of Appeal of the dismissed order in the United States Court of Appeals for the Ninth Circuit on November 9, 2017. PNM cannot predict if such appeal will be successful and, if it is successful, the outcome of further district court proceedings.

Carbon Dioxide Emissions
On August 3, 2015, EPA established final standards to limit CO2 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 filed petitions for review in the DC Circuit to challenge both the Carbon Pollution Standards for new sources and the Clean Power Plan for existing sources. Numerous parties also simultaneously filed motions to stay the Clean Power Plan during the litigation. On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan, but 29 states and state agencies successfully petitioned the US Supreme Court for a stay, which was granted on February 9, 2016. The decision means the Clean Power Plan is not in effect and neither states nor sources are obliged to comply with its requirements. With the US Supreme Court stay in place, the DC Circuit heard oral arguments on the merits of the Clean Power Plan on September 27, 2016 in front of a ten judge en banc panel. However, before the DC Circuit could issue an opinion, the Trump Administration asked that the case be held in abeyance while the rule is re-evaluated, which was granted.

On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order puts forth two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is

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affordable, reliable, safe, secure, and clean.  The order directs the EPA Administrator to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the NSPS for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, and (4) the Legal Memorandum supporting the Clean Power Plan. It also directs the EPA Administrator to notify the US Attorney General of his intent to review rules subject to pending litigation so that the US Attorney General may notify the court and, in his discretion, request that the court delay further litigation pending completion of the reviews. In response to the Executive Order, EPA filed a petition with the DC Circuit requesting the cases challenging the Clean Power Plan be held in abeyance until 30 days after the conclusion of EPA’s review and any subsequent rulemaking, which was granted. In addition, the DC Circuit issued a similar order in connection with a motion filed by EPA to hold cases challenging the NSPS in abeyance.

On October 10, 2017, EPA issued a NOPR proposing to repeal the Clean Power Plan and filed its status report with the court requesting the case be held in abeyance until the completion of the rulemaking on the proposed repeal. The NOPR proposes a legal interpretation concluding that the Clean Power Plan exceeds EPA’s statutory authority. Under the proposed interpretation, Section 111(d) limits EPA’s authority to adopt performance standards to only those physical and operational changes that can be implemented within an individual source. Therefore, measures in the Clean Power Plan that would require power generators to change their energy portfolios by shifting generation from coal to gas and from fossil fuel to renewable energy exceed EPA’s statutory authority. The NOPR was published in the Federal Register on October 16, 2017 and comments were due by April 26, 2018. Any final rule will be subject to judicial review. In a separate but related action, on December 28, 2017, EPA published the Advance Notice of Proposed Rulemaking for replacement of the Clean Power Plan. On December 18, 2017, EPA released an advanced NOPR addressing GHG guidelines for existing electric utility generating units. Comments to EPA’s new rule were due by February 26, 2018. On July 9, 2018, EPA submitted a proposed rule titled “State Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units” to the United States Office of Management and Budget for interagency review.

The proposed federal plan released concurrently with the Clean Power Plan is important to Four Corners and the Navajo Nation. Since the Navajo Nation does not have primacy over its air quality program, EPA would be the regulatory authority responsible for implementing the Clean Power Plan on the Navajo Nation if the Clean Power Plan is ultimately sustained. In addition, the proposed rule recommended that EPA determine it is “necessary or appropriate” for EPA to regulate CO2 emissions on the Navajo Nation. The comment period for the proposed rule closed on January 21, 2016. APS and PNM filed separate comments with EPA on EPA’s draft plan and model trading rules, advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. PNM is unable to predict the financial or operational impacts on Four Corners operations if the Clean Power Plan is ultimately implemented as proposed and EPA determines that a federal plan is necessary or appropriate for the Navajo Nation.

PNM’s review of the CO2 emission reductions standards under the Clean Power Plan is ongoing and the assessment of its impacts will depend on the proposed repeal of the Clean Power Plan, future GHG reduction rulemaking, litigation of any final rule, and other actions the Trump Administration is taking through judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance, if any.

National Ambient Air Quality Standards (“NAAQS”)
The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO2,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO2 NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO2 and the 24-hour SO2 standard. New Mexico is in attainment for the 1-hour NOx NAAQS.

On April 18, 2018, EPA published the final rule to retain the current primary health-based NOx standards of which NO2 is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO2 standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018.

On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO2 NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO2 sources to identify maximum 1-hour SO2 concentrations. This characterization would result in these areas being designated as attainment, nonattainment, or unclassified for compliance

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with the 1-hour SO2 NAAQS.  On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposed deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO2 emissions. The settlement resulted from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree required that: (1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; (2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule.  SJGS and Four Corners SO2 emissions are below the thresholds 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 SO2 non-attainment designations. NMED did not receive a letter.

On August 11, 2015, EPA released the Data Requirements Rule for SO2, telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO2 NAAQS.  On June 3, 2016, NMED notified PNM that air quality modeling results indicated that SJGS was in compliance with the standard. In January 2017, NMED submitted their formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO2 standard. On June 27, 2018, NMED submitted the first annual report for SJGS as required by the Data Requirements Rule. The report recommends that no further modeling is warranted at this time due to decreased SO2 emissions.

On May 14, 2015, PNM received an amendment to its NSR air permit for SJGS, which reflects the revised state implementation plan for regional haze BART and requires the installation of SNCRs as described above. The revised permit also requires the reduction of SO2 emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO2, and particulate matter. These reductions help SJGS meet the NAAQS for these constituents. The BDT equipment modifications were installed at the same time as the SNCRs, in order to most efficiently and cost effectively conduct construction activities at SJGS. See Regional Haze – SJGS above.

On May 29, 2018, EPA released a proposed rule that would retain the primary health-based NAAQS for SOx. EPA is proposing to retain the current 1-hour standard for SO2, which is 75 parts per billion (“ppb”), based on the 3-year average of the 99th percentile of daily maximum 1-hour SO2 concentrations.  SO2 is the most prevalent SOx compound and is used as the indicator for the primary SOx NAAQS.

On October 1, 2015, EPA 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 NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas.

On November 10, 2015, EPA proposed a rule revising its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data is affected by events outside an area’s control. The proposed rule is important in light of the new more stringent ozone NAAQS final rule since western states like New Mexico and Arizona are particularly subject to elevated background ozone transport from natural local sources, such as wildfires, and transported via winds from distant sources, such as the stratosphere or another region or country.

NMED published its 2015 Ozone NAAQS Designation Recommendation Report on September 2, 2016. In New Mexico, NMED is designating only a small area in southern Dona Ana County as non-attainment for ozone. NMED will have responsibility for bringing this non-attainment area into compliance and will look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. According to NMED’s website, “If emissions from Mexico keep New Mexico from meeting the standards, the New Mexico area could remain non-attainment but would not face more stringent requirements over time.”

On February 25, 2016, EPA released guidance on area designations for ozone, which states used to determine their initial designation recommendations by October 1, 2016. On June 6, 2017, the EPA Administrator sent letters to state governors announcing that EPA was extending, by one year, the deadline for promulgating area designations. However, on August 2, 2017, the Trump

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Administration reversed the decision to extend the deadline to issue area designations, thereby requiring EPA to issue designations for ozone attainment areas by October 1, 2017.

On November 6, 2017, EPA released a final rule establishing some, but not all, initial area designations.  In that final rule, San Juan County, New Mexico, where SJGS and Four Corners are located, is designated as attainment/unclassifiable. The only county in New Mexico designated as non-attainment is Dona Ana County.  On April 30, 2018, EPA completed additional area designations for the 2015 ozone standards. In a related matter, EPA published a final rule on March 9, 2018 establishing air quality thresholds that define the classifications assigned to all nonattainment areas for ozone NAAQS. The final rule also establishes the timing of attainment dates for each nonattainment area classification, which are marginal, moderate, serious, severe, or extreme. The rule became effective May 8, 2018.

NMED is required to submit an infrastructure and transport SIP that provides the basic air quality management program to implement the revised ozone standard. This plan is generally due within 36 months from the date the NAAQS is promulgated and is expected to be submitted to the EPA by October 1, 2018. State ozone attainment plans are generally due within five to six years from the date of the ozone NAAQS promulgation and are planned for submittal in 2020 and 2021.

PNM does not believe there will be material impacts to its facilities as a result of NMED’s nonattainment designation of the small area within Dona Ana County. 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.

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 challenged several unrelated mining plan modification approvals, which were each separately approved by OSM.  WEG alleged 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 sought 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.

Of the fifteen claims for relief in the WEG Petition, two concerned SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. SJCC intervened in this matter. The court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the NM District Court. In July 2016, OSM filed a Motion for Voluntary Remand to allow the agency to conduct a new environmental analysis. On August 31, 2016, the court entered an order remanding the matter to OSM for the completion of an EIS by August 31, 2019. The court ruled that mining operations may continue in the interim and the litigation is administratively closed. If OSM does not complete the EIS within the time frame provided, the court will order immediate vacatur of the mining plan at issue absent a further court order based on good cause shown. On March 22, 2017, OSM issued its Notice of Intent to initiate the public scoping process and prepare an EIS for the project. The Notice of Intent provided that, in addition to analyzing the environmental effects of the mining project, the EIS will also analyze the indirect effects of coal combustion at SJGS. The public comment period ended on May 8, 2017 and the EIS resource data submittal phase was completed in November 2017. The draft EIS was made available in May 2018. Public comments were due on July 9, 2018. PNM cannot currently predict the outcome of this matter.
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

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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 court 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 became effective October 14, 2014.
The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting Best Technology Available (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system, which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority.
The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is working with EPA regarding this issue. However, PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS.
On May 23, 2018, several environmental groups sued EPA Region IX in the Ninth Circuit Court over EPA’s failure to timely reissue the Four Corners NPDES permit. The petitioners asked the court to issue a writ of mandamus compelling EPA Region IX to take final action on the pending NPDES permit by a reasonable date. EPA subsequently reissued the NPDES permit on June 12, 2018. The permit does not contain conditions related to the cooling water intake structure rule as EPA determined that the facility has achieved BTA for both impingement and entrainment by operating a closed-cycle recirculation system and no additional conditions are necessary. On July 16, 2018, several environmental groups filed a petition for review with the EPA’s Environmental Appeals Board concerning the reissued permit. The environmental groups alleged that the permit was reissued in contravention of several requirements under the Clean Water Act and does not contain required provisions concerning certain revised effluent limitation guidelines, existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. The coalition is seeking to have the permit remanded to EPA for revision to address these allegations. PNM cannot predict the outcome of this matter.

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 offered 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.  All proposed alternatives establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. 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. The final rule, which became effective on January 4, 2016, 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

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must be incorporated into plants’ NPDES permits. Each plant must comply between 2018 and 2023 depending on when it needs a new or revised NPDES permit.

On April 14, 2017, EPA filed a motion with the United States Court of Appeals for the Fifth Circuit relating to ongoing litigation of the 2016 Steam Electric Effluent Guidelines rule. EPA asked the court to hold all proceedings in the case in abeyance until August 12, 2017 while EPA reconsiders the rule. EPA also asked to be allowed to file a motion on August 12, 2017 to inform the court if EPA wishes to seek a remand of any provisions of the rule so that EPA may conduct further rulemaking, if appropriate. The motion referred to the notice signed by the EPA Administrator on April 12, 2017, which announced EPA’s intent to reconsider this rule, as well as EPA’s administrative stay of the compliance deadlines. On August 22, 2017, the court granted the government’s motion and the litigation is held in abeyance until EPA’s further rulemaking has concluded.

On September 18, 2017, EPA published the final rule for postponement of certain compliance dates, which have not yet passed for the Effluent Limitations Guidelines rule, consistent with the EPA’s decision to grant reconsideration of that rule. The final rule postponed the earliest date on which compliance with the effluent limitation guidelines for these waste streams would be required from November 1, 2018 until November 1, 2020.

Because SJGS is zero discharge for wastewater and is not required to hold a NPDES permit, it is expected that minimal 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. It is expected that minimal to no requirements will be imposed at Reeves Station.

EPA reissued an NPDES permit for Four Corners on June 12, 2018. EPA determined that the guidelines in the 2015 rule are not applicable to this permit because the effective dates of the 2015 effluent guidelines rule were extended. 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, during the next NPDES permit renewal for Four Corners, which will be in 2023. See Cooling Water Intake Structures above. PNM is unable to predict the outcome of these matters or a range of the potential costs of compliance.
Santa Fe Generating Station
PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED also 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. Results of tests conducted by NMED in April 2012 and April 2013 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. 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. However, 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.  Therefore, PNM has agreed to monitor nitrate levels in a limited number of wells under the terms of the renewed discharge permit for the former generating station. 


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)


Effective December 22, 2015, PNM and NMED entered into a memorandum of understanding to address changing groundwater quality conditions at the site. Under the memorandum, PNM will continue hydrocarbon investigation of the site under the supervision of NMED and qualified costs of the work will be eligible for payment through the New Mexico Corrective Action Fund (“CAF”), which is administered by the NMED Petroleum Storage Tank Bureau. Among other things, money in the CAF is available to NMED to make payments to or on behalf of owners and operators for corrective action taken in accordance with statutory and regulatory requirements to investigate, minimize, eliminate, or clean up a release. PNM’s work plan and cost estimates for specific groundwater investigation tasks were approved by the Petroleum Storage Tank Bureau. PNM submitted a monitoring plan consisting of a compilation of the data associated with monitoring activities conducted under the CAF to NMED on October 3, 2016. PNM completed all CAF-related work associated with the monitoring plan and received NMED’s approval. PNM’s contractor prepared a scope of work, which PNM and NMED approved, for the installation of additional monitoring wells and additional sampling of certain existing monitoring wells at the site. These activities were completed in June 2018. A second work plan for the next phase of work, which will include the installation of 19 additional monitoring wells, was submitted to the NMED. Work is expected to be completed in early 2019. Qualified costs of this work are eligible for payment through the CAF.

PNM is unable to predict the outcome of these matters.
Coal Combustion Byproducts Waste Disposal
CCBs consisting of fly ash, bottom ash, and gypsum generated from coal combustion at SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments or landfills. The NMMMD currently regulates placement of ash in the San Juan mine 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.

EPA’s final coal ash rule, which became effective on October 19, 2015, included a non-hazardous waste determination for coal ash. 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.

Because the rule is promulgated under Subtitle D of RCRA, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the 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 requirements.

On December 16, 2016, the Water Infrastructure Improvements for the Nation Act (the “WIIN Act”) was signed into law to address critical water infrastructure needs in the United States. The WIIN Act contains a number of provisions requiring EPA to modify the self-implementing provisions of the current CCB rules under Subtitle D. Among other things, the WIIN Act provides for the establishment of state and EPA permit programs for CCBs, provides flexibility for states to incorporate the EPA final rule for CCBs or develop other criteria that are at least as protective as the EPA’s final rule, and requires EPA to approve state permit programs within 180 days of submission by the state for approval. As a result, the CCB rule is no longer self-implementing and there will either be a state or federal permit program. Subject to Congressional appropriated funding, EPA will implement the permit program in states that choose not to implement a program. Until permit programs are in effect, EPA has authority to directly enforce the self-implementing CCB rule. For facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation where Four Corners is located, EPA is required to develop a federal permit program regardless of appropriated funds. EPA has yet to undertake rulemaking proceedings to implement the CCB provisions of the WIIN Act. There is no time line for establishing either state or federal permitting programs. APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on tribal reservations, including Four Corners. PNM is unable to predict when EPA will be issuing permits for Four Corners.

On September 13, 2017, EPA agreed to evaluate whether to revise the CCB regulations based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCBs, which were premised in part on the provisions of the WIIN Act. In light of the WIIN Act and the petitions for rulemaking, the EPA is considering making additional changes to the CCB rule to provide flexibility to state programs consistent with the WIIN Act. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of the CCB regulations and pursuant to an order issued by the DC Circuit, EPA filed

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


a status report on November 15, 2017 on the challenges to the CCB rule identifying provisions it intends to reconsider. On November 20, 2017, the DC Circuit heard oral arguments from industry groups, environmentalists, and EPA. EPA and the industry groups argued the court should postpone adjudication until EPA completes the reconsideration process for the affected provision. On December 20, 2017, a proposal to remand the CCB rule was transmitted to the Office of Management and Budget for interagency review.

Pursuant to a June 24, 2016 order by the DC Circuit in litigation by industry and environmental groups challenging EPA’s CCB regulations, EPA is required to complete a rulemaking proceeding by June 2019 to address specific technical issues related to the handling of CCBs. On March 15, 2018, EPA proposed its Phase I Remand Rule that includes potential revisions to provide site-specific, risk-based tailoring of groundwater monitoring, corrective action and location restriction requirements of the CCB rule. On June 12, 2018, EPA sent a final CCB revision “fast-track” rule to OMB, which has 90 days to review the rule. The rule only addresses some provisions from the proposed rule released in March 2018. A rule with more substantive changes is expected to follow.

The CCB rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in the future and will likely be influenced by EPA’s rule. 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. Based upon the requirements of the final rule, PNM conducted a CCB assessment at SJGS and made minor modifications at the plant to ensure that there are no facilities which would be considered impoundments or landfills under the rule. PNM would seek recovery from its ratepayers of all CCB costs that are ultimately incurred. PNM does not expect the rule to have a material impact on operations, financial position, or cash flows.

As indicated above, CCBs at Four Corners are currently disposed of in ash ponds and dry storage areas. The CCB rule requires ongoing, phased groundwater monitoring. By October 17, 2017, utilities that own or operate CCB disposal units, such as those at Four Corners must have collected sufficient groundwater sampling data to initiate a detection monitoring program.  To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCB rule’s standards, the rule required the initiation of an assessment monitoring program by April 15, 2018.  If this assessment monitoring program reveals concentrations of certain constituents above the CCB rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by April 2019. Depending upon the results of such groundwater monitoring and data evaluations, Four Corners may be required to take corrective actions, including the closure of certain CCB disposal units, the costs of which cannot be reasonably estimated at this time.
Other Commitments and Contingencies
Coal Supply
SJGS
The coal requirements for SJGS are supplied by SJCC. SJCC holds certain federal, state, and private coal leases. In addition to coal delivered to meet the current needs of SJGS, PNM has prepaid SJCC for certain coal mined but not yet delivered to the plant site. At June 30, 2018 and December 31, 2017, prepayments for coal (including amounts purchased from the exiting SJGS participants discussed below), which are included in other current assets, amounted to $26.3 million and $26.3 million. Additional information concerning the coal supply for SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K.
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. On July 1, 2015, PNM and Westmoreland Coal Company (“Westmoreland”) entered into a new coal supply agreement (“SJGS CSA”), pursuant to which Westmoreland is to supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland is to provide CCB disposal and mine reclamation services for SJGS. Contemporaneous with the entry into the coal-related agreements, Westmoreland entered into a stock purchase agreement (the “Stock Purchase Agreement”) on July 1, 2015 to acquire all of the capital stock of SJCC.


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 SJGS CSA became effective as of 11:59 PM on January 31, 2016, upon the closing under the Stock Purchase Agreement. Upon closing under the Stock Purchase Agreement, Westmoreland’s rights and obligations under the SJGS CSA and the agreements for CCB disposal and mine reclamation services were assigned to SJCC. Westmoreland has guaranteed SJCC’s performance under the SJGS CSA. Pricing under the SJGS CSA is primarily 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 has the option to extend the SJGS CSA, subject to negotiation of the term of the extension and compensation to the miner. In order to extend, the SJGS CSA provides that PNM must give written notice of that intent by July 1, 2018 and the parties must agree to the terms of the extension by January 1, 2019. In addition, the SJPPA obligates each SJGS participant to provide notice to the other participants whether they wish to extend the terms of the SJPPA and the SJGS CSA beyond June 30, 2022. Los Alamos, UAMPS, and Tucson provided notice of their intent to exit SJGS in 2022. Farmington gave notice that it wishes to continue SJGS operations and to extend the terms of both agreements. PNM gave preliminary notice to the other participants that, based on updated coal pricing and other relevant information, PNM does not wish to extend the terms of the SJPPA or the SJGS CSA beyond June 30, 2022. PNM is continuing to analyze the permanent retirement of SJGS in 2022, including plant decommissioning and related coal mine reclamation. The final determination of PNM’s exit from SJGS is subject to NMPRC approval in a formal abandonment proceeding (Note 12). Due to Farmington’s stated interest in continuing SJGS operations beyond 2022, PNM and Westmoreland agreed to extend the July 1, 2018 notice deadline to December 1, 2018.

On March 17, 2018, a coal silo used to supply fuel to SJGS Unit 1 collapsed resulting in an outage. Repairs necessary to return Unit 1 to service were completed by July 5, 2018. See Note 12. PNM notified Westmoreland that this event constituted a “force majeure” under the SJGS CSA and that PNM would be unable to satisfy its minimum obligations to purchase coal for Unit 1 as a result of the event. PNM indicated the obligation to take coal for Unit 1 should be reduced by approximately 113,000 tons, but reserved the right to claim additional reductions related to the event.

The SJGS RA sets forth terms under which PNM acquired the coal inventory, including coal mined but not delivered, of the exiting SJGS participants as of January 1, 2016 and supplied coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and is supplying coal to the SJGS remaining participants over the term of the SJGS CSA. Coal costs under the SJGS CSA are significantly less than under the previous 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 are passed through to PNM’s customers.

In support of the closing under the Stock Purchase Agreement and to facilitate PNM customer savings, NM Capital, a wholly-owned subsidiary of PNMR, provided funding of $125.0 million (the “Westmoreland Loan”) to Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity subsidiary of Westmoreland, to finance WSJ’s purchase of the stock of SJCC (including an insignificant affiliate) under the Stock Purchase Agreement. NM Capital provided the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent. The BTMU Term Loan Agreement became effective as of February 1, 2016, had a maturity date of February 1, 2021, and bore interest at a rate based on LIBOR plus a customary spread. In connection with the BTMU Term Loan Agreement, PNMR, as parent company of NM Capital, guaranteed NM Capital’s obligations to BTMU.

The Westmoreland Loan was a $125.0 million loan agreement among NM Capital, as lender, WSJ, as borrower, and SJCC and its affiliate, as guarantors. The Westmoreland Loan became effective as of February 1, 2016 and had a maturity date of February 1, 2021. The interest rate on the Westmoreland Loan escalated over time and was 9.25% plus LIBOR for the period from February 1, 2017 through January 31, 2018 and 12.25% plus LIBOR beginning February 1, 2018. WSJ paid principal and interest quarterly to NM Capital in accordance with an amortization schedule. In addition, the Westmoreland Loan required that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it was fully repaid. The Westmoreland Loan was secured by the assets of and the equity interests in SJCC and its affiliate. The Westmoreland Loan also included customary representations and warranties, covenants, and events of default. There were no prepayment penalties. See Note 6.

On May 22, 2018, the full principal outstanding under the Westmoreland Loan of $50.1 million was repaid. NM Capital used a portion of the proceeds to repay all remaining principal of $43.0 million owed under the BTMU Term Loan Agreement.

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)


These payments effectively terminated the loan agreements. In addition, PNMR’s guarantee of NM Capital’s obligations was also effectively terminated.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds of $118.7 million with the NMMMD. In order to facilitate the posting of reclamation bonds by sureties on behalf of SJCC, PNMR entered into letter of credit arrangements with a bank under which letters of credit aggregating $30.3 million have been issued.

Four Corners
APS purchasedpurchases 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 NTEC, an entity owned by the Navajo Nation, andunder a new coal supply contract for Four Corners, beginning in July 2016 and expiring in 2031, was entered into with NTEC (the “Four Corners CSA”). that expires in 2031. The BHP subsidiary was retained ascoal comes from reserves located within the mine manager and operator through December 2016.Navajo Nation. NTEC has contracted with Bisti Fuels Company, LLC, a subsidiary of The North American Coal Corporation, took overfor management and operation of the mine effective January 1, 2017.mine. The contract provides for pricing adjustments over its term based on economic indices. The average coal price per MMBTUton under the new contract was approximately 51% higher in the twelve months ended June 30, 2017 than in the twelve months ended June 30, 2016, excluding2016. In the disputed amountstwelve months ended June 30, 2018, the average coal price per delivered ton increased approximately 6.9% over the 2017 prices. As discussed below. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that itsbelow, the Four Corners CSA has been amended. PNM’s share of the increasedcoal costs will beis being recovered through itsthe FPPAC.
Four Corners Coal Supply Arbitration – The owners of Four Corners are obligated to purchase a specified minimum amount of coal each contract year and to pay for any shortfall of coal that they fail to take delivery of below the minimum amount, except when caused by “uncontrollable forces” as defined in the Four Corners CSA.  On June 13, 2017, APS received a demand for arbitration from NTEC in connection with the Four Corners CSA.  NTEC originally sought a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement relating to the annual minimum quantities of coal to be purchased by the Four Corners owners. NTEC also alleged a shortfall in those purchases for the initial contract year, which ended June 30, 2017, of which PNM’s share is estimated to be approximately $6.5 million.2017.  On September 20, 2017, NTEC amended its demand for arbitration removing the request for a declaratory judgment and is now only seeking reliefjudgment. On June 29, 2018, a settlement was reached for the allegeddisputed shortfall in purchases induring the initial contract year.period July 7, 2016 through February 28, 2018. PNM’s share of the settlement payment made to NTEC by the Four Corners owners was $4.9 million. PNM share of the shortfall for the guaranteed minimum purchase of coal for the period March 1, 2018 through June 30, 2018 is $1.4 million. The arbitration was dismissed on July 9, 2018. PNM anticipates that substantially all of anythe amount it ultimately is required to pay wouldunder this settlement agreement will be passedcollected through to customers under PNM’sthe FPPAC. Although PNM cannot predict

Contemporaneous with the timing or outcomeexecution of the arbitration,settlement agreement, the outcome isFour Corners owners and NTEC amended the Four Corners CSA. The amendments reduce required take-or-pay volumes and the base price of coal. The amendments do not expected to have a material impact onextend the term of the Four Corners CSA beyond its financial position, results of operations or cash flows.current July 6, 2031 expiration date.
Coal Mine Reclamation
InAs indicated under Coal Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs in the surface mine pits adjacent to the plant and Four Corners disposes of CCBs in ash ponds and dry storage areas. As discussed in Note 16 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K, in conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA, an updatedthe SJGS participants requested that the coal mine reclamation study was requested byfor SJGS be updated as of December 31, 2016. That reclamation cost estimate reflects the SJGS participants. In 2013, PNM updated its studyterms of the finalnew reclamation costs for bothservices agreement with Westmoreland and continuation of mining operations through 2053, as well as the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimatesanticipated impacts of the final reclamation costs. This estimate reflected that, with the proposed shutdown of SJGSSGS Units 2 and 3 described above,on December 31, 2017. The current estimate for decommissioning the mine providing coal toserving Four Corners reflects the operation of the mine through 2031, the term of the Four Corners CSA.
Based on the 2016 estimates and PNM’s current ownership share of SJGS, would continue to operate through 2053, the anticipated lifePNM’s remaining payments as of SJGS. The 2013 coalJune 30, 2018 for mine reclamation, study indicatedin future dollars, are estimated to be $98.5 million for the surface mines at both SJGS and Four Corners and $127.1 million for the underground mine at SJGS. At June 30, 2018 and December 31, 2017, liabilities, in current dollars, of $40.5 million and $41.4 million for surface mine reclamation costs had increased, including significant increases due to theand $15.4 million and $14.7 million for underground mine reclamation were recorded in other deferred credits.

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)


proposed shutdown of SJGS Units 2 and 3, which would reduce the amount of CCBs generated over the remaining life of SJGS and result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. 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.
In 2015, PNM updated its final reclamation costs estimates to reflect the terms of the new reclamation services agreement with Westmoreland, discussed above, and changes resulting from the approval of the 2015 SJCC Mine Permit Plan. The 2015 reclamation cost estimate reflected that the scope and pricing structure of the reclamation service agreement with Westmoreland would significantly increase reclamation costs. In addition, design plan changes, updated regulatory expectations, and common mine reclamation practices incorporated into the 2015 SJCC Mine Permit reflect an increase in the 2015 reclamation cost estimate. The impacts of these increases, amounting to $16.5 million, were recorded at December 31, 2015.
Upon effectiveness of the CSA and the RA, PNM, on behalf of the SJGS owners, coordinated a more detailed coal mine reclamation cost study, which was completed in the third quarter of 2016. To complete the study, PNM was provided access to the mine site and obtained supporting data from Westmoreland, allowing for the 2015 study to be refined with a more extensive engineering analysis. This reclamation cost estimate reflected the terms of the new reclamation services agreement with Westmoreland and continuation of mining operations through 2053. The study indicated an increase in the reclamation cost estimate. PNM’s $4.8 million share of the increase was recorded in the three months ended September 30, 2016. The current estimate for decommissioning the mine serving Four Corners reflects the operation of the mine through 2031, the term of the new agreement for coal supply.
Based on the 2016 estimates and PNM’s current ownership share of SJGS, PNM’s remaining payments as of September 30, 2017 for mine reclamation, in future dollars, are estimated to be $100.9 million for the surface mines at both SJGS and Four Corners and $127.4 million for the underground mine at SJGS. At September 30, 2017 and December 31, 2016, liabilities, in current dollars, of $41.4 million and $41.0 million for surface mine reclamation and $14.7 million and $14.0 million for underground mine reclamation were recorded in other deferred credits.
As discussed in Note 12, PNM filed its 2017 IRP on July 3, 2017. The conclusions contained in the 2017 IRP indicate that it would be cost beneficial to PNM’s customers for PNM to retire its SJGS capacity in 2022 and for PNM to exit its ownership interest in Four Corners in 2031. IfThe 2017 IRP is not a final determination of PNM’s future generation portfolio. Retiring PNM’s share of SJGS capacity and exiting Four Corners would require NMPRC approval of abandonment filings, which PNM would make at appropriate times in the NMPRC ordersfuture. In the event of the abandonment of those facilities, PNM would be required to remeasure its liability for coal mine reclamation to reflect that reclamation activities would occur sooner than currently anticipated. The remeasurement would likely result in a significant increase in PNM’s liability for SJGS mine reclamation due to a furtheran increase in the amount of fill dirt required to remediate the mine areas, thereby increasing the overall reclamation costs. PNM would be exposed to loss if recovery of the additional costs is not approved by the NMPRC in connection with the NMPRC approvals indicated above. The amount of the increase in the liability would depend on the timing of those approvals and other regulatory actions, as well estimates made at that time of the costs to perform the future reclamation activities, including the then current inflation and discount rates. Preliminary calculations indicate the increase in PNM’s liability for SJGS mine reclamation as of December 31, 2017 would be approximately $35 million for the surface mine and $5 million for the underground mine. PNM would record a regulatory asset for amounts recoverable from ratepayers under existing or future orders of the NMPRC and amounts not recoverable would be expensed. PNM cannot predict what actions the NMPRC might take.

Under the terms of the SJGS CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation costs associated with the supply of coal from the San Juan mine. The SJGS owners entered into a reclamation trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the UG-CSA.obligations. 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 reclamation trust, and periodically deposit funds into the reclamation 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. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels. PNM funded $5.8 million in 2017. Based on PNM’s reclamation trust fund balance at SeptemberJune 30, 2017,2018, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $5.8 million in 2017, $8.3$7.2 million in 2018, and $8.7 million in 2019.2019, and $9.2 million in 2020.
Under the Four Corners CSA, which became effective on July 7, 2016, PNM is required to fund its ownership share of estimated final reclamation costs in thirteen annual installments, beginning on August 1, 2016, into an irrevocable escrow account solely dedicated to the final reclamation cost of the surface mine at Four Corners. PNM contributed $2.3 million to the escrow account in July 2017 and anticipates providing additional funding of $2.1$2.3 million in each of 2018 and 2019.

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 collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from retail customers 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. 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.

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 an 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

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)


provision of the settlement agreement, and underpaidagreement. 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.

PVNGS Liability and Insurance Matters
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with this act, the PVNGS participants are insured against public liability exposure for a nuclear incident up to $13.413.2 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers. The remaining $13.012.7 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 $5.8 million, to be adjusted periodically for inflation.

The PVNGS participants maintain 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”). The primary policy offered by NEIL contains a sublimit of $2.25 billion for non-nuclear property damage. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium adjustments of $5.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. 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. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast long-term weather patterns. Public policy, local, state and federal regulations, and litigation regarding water could also impact PNM operations. To help mitigate these risks, PNM has secured permanent groundwater rights for the existing plants at Reeves Station, Rio Bravo, Afton, Luna, Lordsburg, and La Luz. 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 deliveries) could pose a threat of reduced water availability for these plants.

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For SJGS and Four Corners, PNM and APS have negotiated an agreement with the more senior water rights holders (tribes, municipalities, and agricultural interests) in the San Juan basin to mutually share the impacts of water shortages with tribes and other water users in the San Juan basin. The agreement to share shortages in 2017 through 2020 has been negotiated and awaits endorsementendorsed by the parties and is being reviewed by the New Mexico Office of the State Engineer.
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 40 years.
PVNGS Water Supply Litigation
In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows.

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San Juan River Adjudication
In 1975, the State of New Mexico filed an action in New MexicoNM 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, formerthen 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. The issues have been fully briefed andOn April 3, 2018, the matter is pendingNew Mexico Court of Appeals issued an order affirming the decision of the NM District Court. Several parties filed motions requesting a rehearing with the New Mexico Court of Appeals.Appeals seeking clarification of the order, which were denied. Petitions have been filed with the NM Supreme Court regarding denial of those motions. The petitions are in the process of being briefed. The court has not yet taken any action in response to these motions. Adjudication of non-Indian water rights is ongoing.
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 byand adjudicated to the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin.Basin and which have priority in times of shortages. 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 and maintaining the rights-of-way, as well as for capital improvements. 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 Countycounty 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. On January 4, 2016, the utilities filed an Application for Interlocutory Appeal from the state court, which was denied. On March 28, 2017, the utilities filed a Writ of Certiorari with the NM Supreme Court, which was denied. The matter will proceedis proceeding in New MexicoNM District Court. The utilities and Bernalillo County reached a standstill agreement whereby the Countycounty would not take any enforcement action against the

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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 Countycounty 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.
Navajo Nation Allottee Matters
A putative class action was
In September 2012, 43 landowners filed againsta 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 and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffstransmission line. The landowners 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 areis a rights-of-way granteesgrantee 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, theThe allottees filed a motion to dismiss their appeal with prejudice.  Onprejudice, which was granted in April 2, 2014, the allottees’ appeal was dismissed with prejudice.2014. Subsequent to

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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 renewalsindicating that were previously contested.  The letter indicated that thecertain 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 StatesNM District Court for the District of New Mexico regarding the approximately 15.49 acres of land at issue. On December 1, 2015, the court ruled that PNM could not condemn two of the five allotments at issue based on the Navajo Nation’s fractional interest in the land. PNM’sPNM filed a motion for reconsideration of this ruling, which was denied. On March 31, 2016, the Tenth Circuit granted PNM’s petition to appeal the December 1, 2015 ruling. On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. Both matters have been consolidated and are stayed while PNM pursues its appeal before the Tenth Circuit. On June 27, 2016, PNM filed its opening brief in the Tenth Circuit. Amicus briefs were filed in support of PNM’s position. On October 5, 2016, the United States, the Navajo Nation, and individual allottees filed their response briefs. After the response briefs were filed, other entities requested leave to file amicus briefs addressing arguments raised in the United States’ response brief.consolidated. Oral argument before the Tenth Circuit was heard on January 17, 2017. On May 26, 2017, the Tenth Circuit affirmed the district court. On July 8, 2017, PNM filed a Motion for Reconsideration en banc with the Tenth Circuit. On July 21, 2017, the court denied PNM’s Motion for Reconsideration. On July 26, 2017, PNM filed a motion to stay implementation of the court’s decision,Circuit, which was denied. PNM is considering all of its procedural options going forward inThe NM District Court stayed the litigation. On September 11, 2017, PNM filed an Application for Extension of Time to File a Petition for Writ of Certiorari in the US Supreme Court. PNM’s application for an extension of time to November 20, 2017 was granted. On October 23, 2017, the parties filed a Joint Motion to Stay the federal district court case for 90 days based on the Navajo Nation’s acquisition of interests in two additional allotments and the unresolved ownership of the fifth allotment due to the owner’s death. On November 20, 2017, PNM filed its Petition for Writ of Certiorari with the US Supreme Court. On April 30, 2018, the US Supreme Court declined to hear PNM’s Petition for Writ of Certiorari. The court granted this motion on October 24, 2017.underlying litigation continues in the NM District Court.
PNM cannot predict the outcome of these matters.


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Sales Tax Audits

In November 2011, PNMR completed the sale of its retail electric provider, which operated in Texas under the name First Choice Power (“First Choice”). Under the sale agreement, PNMR is contractually obligated for First Choice’s taxes relating to periods prior to the sale.

The Texas Comptroller of Public Accounts (“Comptroller”) has initiated audits of First Choice’s sales and use tax filings and miscellaneous gross receipts tax filings for periods prior to the sale. During the course of the audits, PNMR accrued an immaterial liability for items identified in the audits for which PNMR believed an unfavorable resolution was probable. The Comptroller has issued notifications of audit results indicating additional tax due of $5.0 million, plus penalties and interest. The primary issue in dispute is the disallowance by the auditor of the tax benefits of bad debt charge-offs and billing credits. On behalf of First Choice, PNMR filed requests for redetermination for both audits.

PNMR has engaged in continued discussions with the Comptroller, as well as supplying additional documentation in support of PNMR’s positions. If PNMR and the Comptroller do not reach agreement, this matter will go to hearing with the Texas State Office of Administrative Hearings. Although PNMR believes its positions are correct, it is unable to predict the outcome of this matter.

(12)Regulatory and Rate Matters

The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K.
PNM

New Mexico General Rate Cases

New Mexico 2015 General Rate Case (“NM 2015 Rate Case”)

On August 27, 2015, PNM filed an application with the NMPRC for a general increase in retail electric rates. The application proposed a revenue increase of $123.5 million, including base non-fuel revenues of $121.7 million. PNM’s application was based on a future test year (“FTY”) period beginning October 1, 2015 and proposed a ROE of 10.5%. The primary drivers of PNM’s identified revenue deficiency were the cost of infrastructure investments, including depreciation expense based on an updated depreciation study, and a decline in energy sales as a result of PNM’s successful energy efficiency programs and economic factors.

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The application included several proposed changes in 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 higher customer and demand charges, a revenue decoupling pilot program applicable to residential and small commercial 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. On March 2, 2016, the NMPRC required PNM to file supplemental testimony regarding the treatment of renewable energy in PNM’s FPPAC. See Renewable Portfolio Standard below. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016, pursuant to the terms of the initial sales-leaseback transactions (Note 6)13). A subsequent public hearing was held in June 2016. After the June hearing, PNM and other parties were ordered to file supplemental briefs and to provide final recommended revenue requirements that incorporated fuel savings that PNM implemented effective January 1, 2016 from PNM’s SJGS coal supply agreement (“SJGS CSA”) (Note 11).  PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current SJGS CSA, (Note 11), which also reduced the request for base non-fuel related revenues by $0.2 million to $121.5 million.

On August 4, 2016, the Hearing Examiner in the case issued a recommended decision (“(the “August 2016 RD”).  The August 2016 RD proposed an increase in non-fuel revenues of $41.3 million compared to the $121.5 million increase requested by PNM. Major components of the difference in the increase in non-fuel revenues proposed in the August 2016 RD, included:


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A ROE of 9.575% compared to the 10.5% requested by PNM
Disallowing recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying three leases of portions of PVNGS Unit 2 (Note 6)13); the August 2016 RD proposed that power from the previously leased assets, aggregating 64.1 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expenses (other than property taxes, which were $0.8 million per year at that time)when the August 2016 RD was issued), but the customers would not bear any capital or depreciation costs other than those related to improvements made after the date of the original leases
Disallowing recovery from retail customers of the rent expense, which aggregates $18.1 million per year, under the four leases of capacity in PVNGS Unit 1 that were extended for eight years beginning January 15, 2015 and the one lease of capacity in PVNGS Unit 2 that was extended for eight years beginning January 15, 2016 (Note 6)13) and related property taxes, which were $1.5 million per year at that time;when the August 2016 RD was issued; the August 2016 RD proposed that power from the leased assets, aggregating 114.6 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expense, except that customers would not bear rental costs or property taxes
Disallowing recovery of the costs of converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS, (Note 11); PNM’s share of the costs of installing the BDT equipment was $52.3 million of which $40.0 million was included in rate base in PNM’s rate request
Disallowing recovery of $4.5 million of amounts recorded as regulatory assets and deferred charges

The August 2016 RD recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. The August 2016 RD also proposed that all fuel costs be removed from base rates and be recovered through the FPPAC. The RD would credit retail customers with 100% of the New Mexico jurisdictional portion of revenues from “refined coal” (a third-party pre-treatment process) at SJGS. In addition, the August 2016 RD would remove recovery of the costs of power obtained from New Mexico Wind from the FPPAC and include recovery of those costs through PNM’s renewable energy rider discussed below. The August 2016 RD recommended continuation of the renewable energy rider and certain aspects of PNM’s proposals regarding rate design, but would not approve certain other rate design proposals or PNM’s request for a revenue decoupling pilot program. The August 2016 RD proposed approving PNM’s proposals for revised depreciation rates (except for requiringthe August 2016 RD would require depreciation on Four Corners be calculated based on a 2041 life rather than the 2031 life proposed by PNM), the inclusion of construction work in progress in rate base, and ratemaking treatment of the “prepaid pension asset.” The August 2016 RD proposed retail customers receive 100% of the New Mexico jurisdictional portion of revenues from “refined coal” (a third-party pre-treatment process) at SJGS. The August 2016 RD did not preclude PNM from supporting the prudence of the PVNGS purchases and lease renewals in its next general rate case and seeking recovery of those costs. PNM disagreed with many of the key conclusions reached by the Hearing Examiner in the August 2016 RD and filed exceptions to defend its prudent utility investments. Other parties also filed exceptions to the August 2016 RD.  

The
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On September 28, 2016, the NMPRC issued an order on September 28, 2016 that authorized PNM to implement an increase in non-fuel rates of $61.2 million, effective for bills sent to customers after September 30, 2016. The order generally approved the August 2016 RD, but with certain significant modifications. The modifications to the August 2016 RD included:

Inclusion of the January 2016 purchase of the assets underlying three leases of capacity, aggregating 64.1 MW, of PVNGS Unit 2 at an initial rate base value of $83.7 million; and disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW was being leased by PNM, which aggregated $43.8 million when the order was issued
FullAllowing full recovery of the rent expense and property taxes associated with the extended leases for capacity, aggregating 114.6 MW, in Palo Verde Units 1 and 2
Disallowance of the recovery of any future contributions for PVNGS decommissioning costs related to the 64.1 MW of capacity purchased in January 2016 and the 114.6 MW of capacity under the extended leases
Recovery of assumed operating and maintenance expense savings of $0.3 million annually related to BDT

On September 30, 2016, PNM filed a notice of appeal with the NM Supreme Court regarding the order in the NM 2015 Rate Case. Subsequently, NEE, NMIEC, and ABCWUA filed notices of cross-appeal to PNM’s appeal. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which stated PNM is appealing the NMPRC’s determination that PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing BDT equipment on SJGS Units 1 and 4. Specifically,In addition, PNM’s statement indicated it is appealing the following specific elements of the NMPRC’s order:

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Disallowance of recovery of the full purchase price, representing fair market value, of the 64.1 MW of capacity in PVNGS Unit 2 purchased in January 2016
Disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity was leased by PNM
Disallowance of recovery of future contributions for PVNGS decommissioning attributable to the 64.1 MW of purchased capacity and the 114.6 MW of capacity under the extended leases
Disallowance of recovery of the costs of converting SJGS Units 1 and 4 to BDT

The issues that are being appealed by the various cross-appellants include:

The NMPRC allowing PNM to recover the costs of the lease extensions for the 114.6 MW of PVNGS Units 1 and 2 and any of the purchase price for the 64.1 MW in PVNGS Unit 2
The NMPRC allowing PNM to recover the costs incurred under the new coal supply contract for Four Corners CSA
The revised method to collect PNM’s fuel and purchased power costs under the FPPAC
The final rate design
The NMPRC allowing PNM to include the “prepaid pension asset” in rate base

NEE subsequently filed a motion for a partial stay of the order at the NM Supreme Court. This motion was denied. The NM Supreme Court stated that the court’s intent was to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits.

On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule was completed on July 21, 2017. Oral argument at the NM Supreme Court is scheduled forwas held on October 30, 2017. Although appeals of regulatory actions of the NMPRC have a priority at the NM Supreme Court under New Mexico law, there is no required time frame for the court to act on the appeals.

GAAP requires that a loss is to be recognized when it is probable that a loss has been incurred and the amount of loss can be reasonably estimated. When there is a range of the amount of the probable loss, the minimum amount of the range is to be accrued unless an amount within the range is a better estimate than any other amount. As of September 30, 2016, PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicatesindicated it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the issues, those issues would be

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remanded back to the NMPRC for further action. As of September 30, 2016, PNM continues to estimate thatestimated it willwould take a minimum of 15 months, from the date PNM filed its appeal, for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order willwould remain in effect. PNM has concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case; that the minimum amount of loss continues to bewas 15 months of capital cost recovery whichthat the order disallowed for PNM’s investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT; and that no amount within the range of possible loss iswas a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million inat September 30, 2016 for the capital costs that willwould not be coveredrecovered during that 15 month15-month appeal period. In addition, PNM recorded a pre-tax regulatory disallowance for $4.5 million of costs recorded as regulatory assets and deferred charges (which the order disallowed and which PNM did not challenge in its appeal) since PNM cancould no longer assert that those assets arewere probable of being recovered through the ratemaking process. Additional

PNM also evaluated the accounting consequences of the issues that are being appealed by the cross-appellants. PNM does not believe the issues raised in the cross-appeals have substantial merit. Accordingly, PNM does not believe that the likelihood of the cross-appeals being successful is probable and, therefore, no loss has been recorded related to the issues subject to the cross-appeals.

Since the NM Supreme Court did not issue a decision on the appeals related to the NM 2015 Rate Case by December 31, 2017, which was 15 months from the date of the NMPRC’s order in that case, PNM reevaluated the accounting consequences of the order in the NM 2015 Rate Case. At December 31, 2017, PNM estimated the most likely period for the NM Supreme Court to issue a decision in the case and for the NMPRC to take action on any remanded issues was seven months. As a result, PNM recorded an additional loss of $3.1 million at December 31, 2017, representing a disallowance of seven months of capital cost recovery that the order disallowed.

Since the NM Supreme Court did not issue a decision by June 30, 2018, PNM again reevaluated the estimated time frame it would take for the resolution of this matter. PNM continues to believe that it is reasonably possible that PNM will be successful on the issues it is appealing and that it is not probable the cross appeals will be successful. However, based on the proceedings to date in the appeal process and other actions by the NM Supreme Court, PNM estimates it will take an additional five months from June 30, 2018 for the NM Supreme Court to issue a decision and for any remanded issues to be addressed by the NMPRC. Accordingly, PNM recorded an additional loss of $1.8 million at June 30, 2018, representing an additional disallowance of capital costs that will not be recovered through November 30, 2018. Further losses will be recorded if the currently estimated 15 month time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is extended.

The NMPRC’s order approved PNM’s request to record a regulatory asset to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from an extension of the income tax provision for fifty percent bonus depreciation. The impact, net of federal income taxes, amounting to $2.1 million was reflected as a reduction of income tax expense in September 2016.

PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurredprudent and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is

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reasonably possible that its appeals will be successful, it cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record further pre-tax losses related to the capitalized costs for any unsuccessful issues. The impacts of not recovering future contributions for decommissioning would be recordedrecognized in future periods.periods reflecting that rates charged to customers would not recover those costs as they are incurred. The amounts of any such losses to be recorded would depend on the ultimate outcome of the appeal and NMPRC process, as well as the actual amounts reflected on PNM books at the time of the resolution. However, based on the book values recorded by PNM as of SeptemberJune 30, 2017,2018, such losses could include:

The remaining costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity in excess of the recovery permitted under the NMPRC’s order; the net book value of such excess amount was $76.9$74.4 million, after considering the losslosses recorded in 2016to date
The undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity in PVNGS Unit 2 purchased by PNM in January 2016 was being leased by PNM; the net book value of these improvements was $39.9$38.6 million, after considering the losslosses recorded in 2016to date
The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $50.0$50.5 million, after considering the losslosses recorded in 2016to date

Also,
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Although PNM does not believe the issues raised in the cross-appeals have substantial merit, PNM is unable to predict what decision the NM Supreme Court will reach. PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, ifprobable, it is unable to predict what decision the NM Supreme Court will reach. If the NM Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any cost recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases, aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $153.4$148.7 million (which amount includes $76.9$74.4 million that is the subject of PNM’s appeal discussed above) at SeptemberJune 30, 2017,2018, after considering the losslosses recorded in 2016.to date. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and “prepaid pension asset” in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have a financial impact to PNM.

PNM is unable to predict the outcome of this matter.

New Mexico 2016 General Rate Case (“NM 2016 Rate Case”)

On December 7, 2016, PNM filed an application with the NMPRC for a general increase in retail electric rates. PNM did not include any of the costs disallowed in the NM 2015 Rate Case that are at issue in its pending appeal to the NM Supreme Court. Key aspects of PNM’s request are:were:

An increase in base non-fuel revenues of $99.2 million
Based on a FTY beginning January 1, 2018 (the NMPRC’s rules specify that a FTY is a 12 month period beginning up to 13 months after the filing of a rate case application)
ROE of 10.125%
Drivers of revenue deficiency
◦Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (Note 11)
◦Infrastructure investments, including environmental upgrades at Four Corners
◦Declines in forecasted energy sales due to successful energy efficiency programs and other economic factors
◦Updates in the FERC/retail jurisdictional allocations
Proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation
◦Increased customer and demand charges
◦A “lost contribution to fixed cost” mechanism applicable to residential and small commercial customers to address the regulatory disincentive associated with PNM’s energy efficiency programs


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The NMPRC scheduled a public hearing to begin on June 5, 2017, ordered that a settlement conference should be held, and that any resulting stipulation should be filed by March 27, 2017. Settlement discussions were held, but no agreements were reached by March 27, 2017. PNM and several intervenors filed an unopposed motion with the NMPRC to extend by one month the procedural schedule, including2017, after which the date for filing a stipulation. On April 12, 2017, the NMPRC issued an order modifying the procedural schedule to allow for additional settlement discussion. Under the revised schedule, any settlement stipulation was to be filed by April 27, 2017. On April 27, 2017, PNM and several intervenors filed a motion with the NMPRC to extend the deadline for filing a stipulation. The motion was granted by the Hearing Examiners and inextended. In early May 2017, PNM and thirteen intervenors (the “Signatories”) entered into a comprehensive stipulation. On May 12, 2017, the Hearing Examiners issued an order rejecting the stipulation in its then current form, but allowed the Signatories to revise the stipulation. On May 23, 2017, the Signatories filed a revised stipulation that addressed the issues raised by the Hearing Examiners in their order.Examiners. NEE iswas the sole party opposing the revised stipulation. The terms of the revised stipulation, include:which required NMPRC approval in order to take effect, included:

A revenue increase totaling $62.3 million, with an initial increase of $32.3 million beginning January 1, 2018 and the remaining increase beginning January 1, 2019
A ROE of 9.575%
Full recovery of thePNM’s investment in SCRs at Four Corners with a debt-only return
An agreement to not to adjustimplement non-fuel base rate changes, other than changes related to bePNM’s rate riders, with an effective date prior to January 1, 2020
An agreement to adjust the January 2019 increase for certain changes in federal corporate tax laws enacted prior to November 1, 2018 and effective and applicable to PNM by January 1, 2019 and to true-up PNM’s cost of debt for refinancing transactions through 2018
Returning to customers over a three-year period the benefit of the reduction in the New Mexico corporate income tax rate (Note 13)14) to the extent attributable to PNM’s retail operations

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PNM would withdraw its proposal for a “lost contribution to fixed cost” mechanism with the issue to be addressed in a future docket

On May 24, 2017, the NMPRC issued an order, which resultedPNM would perform a cost benefit analysis in the tollingits 2020 IRP of the statutory suspension period for two monthsimpact of a possible early exit from Four Corners in 2024 and extending the suspension of the rate increase until January 6, 2018. The NMPRC can further extend the suspension period for an additional two months. 2028

A hearing on the revised stipulation was held in August 2017. On October 31, 2017, the Hearing Examiners issued a Certification of Stipulation recommending a Modified Revised Stipulation. The revised stipulation requires the approval of the NMPRC in ordersignificant changes to take effect.

If the NMPRC approves the revised stipulation in the Hearing Examiners’ Modified Revised Stipulation included:

Identifying PNM’s decision to continue its participation in Four Corners as imprudent
Disallowing PNM’s ability to collect a debt or equity return on its $90.1 million investment in SCRs at Four Corners and on $58.0 million of projected capital improvements during the period July 1, 2016 through December 31, 2018
Recommending a temporary disallowance of $36.8 million of PNM’s projected capital improvements at SJGS through December 31, 2018

On December 20, 2017, the NMPRC issued anOrder Partially Adopting Certification of Stipulation, which approved the Hearing Examiners’ Certification of Stipulation with certain changes. Substantive changes from the Certification of Stipulation included requiring the impacts of changes related to the reduction in the federal corporate income tax rate be implemented effective January 1, 2018 rather than January 1, 2019 and deferring further consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to a future proceeding.

On December 28, 2017, PNM filed a Motion for Rehearing and Request for Oral Argumentasking the NMPRC to vacate their December 20, 2017 order and allow the parties to present oral argument. Additionally, several Signatories to the revised stipulation filed a Joint Motion for Partial Rehearing asking that the NMPRC approve the revised stipulation without modification. On January 2, 2018, NEE filed a response urging the NMPRC to reject PNM’s Motion.

On January 3, 2018, the NMPRC vacated its December 20, 2017 order and granted the motions for rehearing. The rehearing was held on January 10, 2018.

The NMPRC issued a Revised Order Partially Adopting Certification of Stipulation dated January 10, 2018 (the “Revised Order”). The Revised Order approved the Hearing Examiners’ Certification of Stipulation with certain changes including:

Requiring the impacts of changes related to the reduction in the federal corporate income tax rate and PNM’s cost of debt (aggregating an estimated $47.6 million) be implemented in 2018 rather than January 1, 2019
Deferring further consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to PNM’s next rate case
Disallowing PNM’s ability to collect an equity return on its $90.1 million investment in SCRs at Four Corners and on $58.0 million of projected capital improvements during the period July 1, 2016 through December 31, 2018, but allowed recovery of the total $148.1 million of investments with a debt-only return
Requiring PNM to reduce the requested $62.3 million increase in non-fuel revenue by $9.1 million
Implementation of the first phase of the rate increase for services rendered, rather than bills sent, beginning February 1, 2018 and of the second phase for services rendered beginning January 1, 2019

On January 16, 2018, PNM requested clarifying changes to the Revised Order to adjust the $9.1 million reduction to $4.4 million, asserting that $4.7 million of the reduction was duplicative. On January 17, 2018, the NMPRC issued an order approving the adjustment requested by PNM. On January 19, 2018, PNM and the Signatories filed a joint notice of acceptance of the Revised Order, as amended. On January 31, 2018, the NMPRC issued an order closing the docket in the NM 2016 Rate Case. After implementation of changes to the federal corporate income tax rate and cost of debt, the final order results in a net increase to PNM’s non-fuel revenue requirement of $10.3 million. PNM implemented 50% of the approved increase for service rendered beginning February 1, 2018 and will implement the rest of the increase for service rendered beginning January 1, 2019.

GAAP would requirerequired PNM to recognize a loss to reflect that PNM will not earn an equity return on its$148.1 million of investments in SCRs at Four Corners. The loss would beAs of December 31, 2017, PNM recorded as a pre-tax regulatory disallowance as of the date of NMPRC approval.$27.9 million. The amount of

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the loss would bewas calculated by determining the present value of disallowed cash flows, which would equalequals the difference between the cash flows resulting from recovery of those investments with aat PNM’s embedded cost of debt only return and the cash flows with a full return on investment (including an equity component), and discounting the differences at PNM’s WACC. Such amount would depend

On February 7, 2018, NEE filed a notice of appeal with the NM Supreme Court asking the court to review the NMPRC’s decisions in the NM 2016 Rate Case. On March 7, 2018, NEE filed its statement of issues with the NM Supreme Court requesting, among other things, that the NMPRC be required to identify PNM’s decision to continue its participation in Four Corners as imprudent and to deny any recovery related to PNM’s $148.1 million investments in that facility. NEE’s Brief in Chief was filed on July 16, 2018 and PNM’s Answer Brief is due on September 12, 2018. Several parties to the final costscase have intervened in the appeal as intervenor-appellees in support of the SCRsNMPRC’s final decisions in the Revised Order. Although PNM does not believe it is probable that NEE’s appeal will be successful, it is unable to predict what decision the NM Supreme Court will reach. If the NM Supreme Court were to remand the case to the NMPRC and other factors and assumptions at the dateNMPRC identified PNM’s continued involvement in Four Corners as imprudent with no recovery of NMPRC approval. Based on the stipulation and PNM’s current assumptions,$148.1 million of investments in Four Corners, PNM estimates the regulatory disallowance would be approximately $21 million.required to record additional losses for the remaining amount of those investments (after considering the $27.9 million disallowance recorded in 2017). In addition, PNM’s future investments in Four Corners, which could be required under the participation agreement governing that facility, could also be subject to disallowance. PNM cannot predict the outcome of this matter.

Investigation/Rulemaking Concerning NMPRC Ratemaking Policies

On March 22, 2017, the NMPRC issued an order opening an investigation and rulemaking to simplify and increase “the transparency of NMPRC rate cases by reducing the number of issues litigated in rate cases,” and provide a “more level playing field among intervenors and NMPRC staff on the one hand, and the utilities on the other.” The order posed the following questions: whether a standardized method should be established for determining ROE; should the ROE be subject to reward or penalty based on utilities meeting or failing to meet certain metrics, which could include customer complaints, outages, peak demand reductions, and RPS and energy efficiency compliance; whether recovery of utility rate case expenses should be limited to 50% unless the case is settled; whether intervenors should be allowed to recover their expenses if the NMPRC accepts their position; whether parties should have access to software used by utilities to support their positions; and how regulatory assets should be authorized and recovered. Initial comments were filed in July 2017 and a public workshop was held in September 2017. Additionalseveral public workshops are scheduled in November 2017.have been held. PNM cannot predict the outcome of this proceeding.


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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. PNM files annual renewable energy procurement plans for approval by the NMPRC. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are minimums of 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 that utilities 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 makes renewable procurements consistent with the NMPRC approved plans. PNM recovers certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below.

Included in PNM’s approved procurement plans are the following renewable energy resources:
107157 MW of PNM-owned solar PV facilities, including 40 MW constructed in 2015 that were identified as a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11) and are being recovered in the base rates provided in the NM 2015 Rate Case discussed above rather than through PNM’s renewable energy rider; and an additional procurement of 1.550 MW of PNM-owned solar PV facilities to supplyapproved by the energy sold underNMPRC in PNM’s voluntary2018 renewable energy tariffprocurement plan that will be constructed in 2018 and 2019
A PPA through 20272044 for the output of New Mexico Wind, having ana current aggregate capacity of 204 MW, and a PPA through 2035 for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW
A PPA through 2042 for the output of the Lightning Dock Geothermal facility; the geothermal facility began providing power to PNM in January 2014; the current capacity of the facility is 4 MW
Solar distributed generation, aggregating 81.691.9 MW at SeptemberJune 30, 2017,2018, owned by customers or third parties from whom PNM purchases any net excess output and RECs

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Solar and wind RECs as needed to meet the RPS requirements

PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan met RPS and diversity requirements within the RCT in 2016 and 2017 using existing resources and did not propose any significant new procurements. The NMPRC approved the plan in November 2015, and, after granting a rehearing motion to consider issues regarding the rate treatment of certain customers eligible for a cap on, or an exemption from, RPS procurement, the NMPRC again approved the plan in an order issued on February 3, 2016. The NMPRC deferred issues related to capped and exempt customers to PNM’s NM 2015 Rate Case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The NM 2015 Rate Case and show cause proceeding were to examine whether PNM miscalculated the FPPAC factor and base fuel costs in its treatment of renewable energy costs and application of the renewable procurement cost caps and exemptions. The show cause proceeding was stayed pending the outcome of the NM 2015 Rate Case. The September 28, 2016 order in the NM 2015 Rate Case directed that the cost of New Mexico Wind be recovered through PNM’s renewable rider, rather than the FPPAC, and ordered certain other modifications regarding the accounting for renewable energy in PNM’s FPPAC. These modifications do not affect the amount of fuel and purchased power or renewable costs that PNM will collect. No action has been taken in the show cause proceeding and PNM cannot predict its outcome.

PNM filed its 2017 renewable energy procurement plan on June 1, 2016. The plan met RPS and diversity requirements for 2017 and 2018 using existing resources and PNM did not propose any significant new procurements. PNM projected that its plan would slightly exceed the RCT in 2017 and would be within the RCT in 2018. PNM requested a variance from the RCT in 2017 to the extent the NMPRC determined a variance was necessary. A public hearing was held on September 26, 2016. On October 21, 2016, the Hearing Examiner issued a recommended decision recommending that the plan be approved as filed and also found that a variance from the RCT was not required. The NMPRC approved the recommended decision on November 23, 2016.

On June 1, 2017, PNM filed its 2018 renewable energy procurement plan. PNM is requestingrequested approval to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; approval to procure an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; approval to procure 50 MW of new

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solar facilities to be constructed beginning in 2018;2018, and various other requests, including the continuation of customer REC purchase programs and other purchases of RECs to ensure annual compliance with the RPS. PNM’s proposed procurement costcosts for 2018 and 2019 will be within the RCT. The plan is also seekingsought a variance from the “other” diversity category in 2018 due to a revised production forecast of the Lightning Dock Geothermal facility in 2018. PNM also requested to adjust its annual renewable energy rate rider to collect the costs of renewable resources. On June 14, 2017, the NMPRC issued an initial order appointing a Hearing Examiner and suspending the proposed rate rider adjustment. A public hearing on the application was held in September 2017. On October 17, 2017, the Hearing Examiner issued a recommended decision that PNM’s 2018 renewable energy procurement plan be approved by the NMPRC, except for the re-powering of Lightning Dock Geothermal and PNM’s request to procure 50 MW of new solar facilities. The Hearing Examiner recommended that the PPA for the output of energy from Lightning Dock Geothermal be terminated effective January 1, 2018. The Hearing Examiner also recommended that the 50 MW solar projects not be approved and that PNM be required to issue another all-renewables RFP within 10 days of the issuance of a final order allowing developers to utilize PNM-owned sites to construct facilities, the output from which facilities would be sold to PNM through PPAs. PNM strongly disagrees withfiled exceptions contesting the Hearing Examiner’s recommendationsproposals. On November 15, 2017, the NMPRC issued an order approving PNM’s plan and believes they are unlawful and againstrejecting the weight of evidence. ExceptionsHearing Examiner’s recommendations. On November 29, 2017, NMIEC filed an appeal with the NM Supreme Court objecting to the recommended decisionfuel allocation methodology. On December 14, 2017, NEE filed a motion to intervene and cross-appeal objecting to the approval of the 50 MW of new solar facilities. On December 18, 2017, PNM filed a motion to intervene, which was granted. NMIEC filed a motion for a partial stay of the NMPRC order, which was denied. On June 20, 2018, NEE filed its Brief in Chief with the NM Supreme Court stating, among other things, that PNM’s process favored ownership of the 50 MW solar facilities compared to PPAs. Answer briefs are due on October 27, 2017.September 4, 2018. PNM cannot predict the outcome of this matter.

On June 1, 2018, PNM filed its 2019 renewable energy procurement plan. The plan meets RPS and diversity requirements for 2019 and 2020 using resources already approved by the NMPRC and did not propose any significant new procurements. PNM projects that the plan will file its exceptions timelybe within the RCT in 2019 and will vigorously contestslightly exceed the RCT in 2020. The Hearing Examiner’s proposals regarding Lightning Dock GeothermalExaminer assigned to the case issued a procedural order that requires NMPRC staff and the requirement that PNM allow developersany intervenors to construct renewable facilitiesfile testimony by September 6, 2018 and sets hearings to begin on PNM-owned sites.September 27, 2018. PNM cannot predict the outcome of this matter.
Renewable Energy Rider
The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh

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basis. In PNM’s NM 2015 Rate Case, the NMPRC authorized continuation of the renewable rider. PNM recorded revenues from the rider of $11.8 million and $10.7 million in the three months ended September 30, 2017 and 2016 and $32.4 million and $27.3 million in the nine months ended September 30, 2017 and 2016.

In its 20162018 renewable energy procurement plan case, PNM proposed to collect $42.4$43.5 million in 2016.for the year. The 2016 rider adjustment was approved as part of the order issued February 3, 2016 approving the 2016 renewable energy plan. In its 20172018 renewable energy procurement plan became effective on January 1, 2018. PNM proposed to collect $50.0 million throughrecorded revenues from the rider in 2017. The increase, as compared with the amount the NMPRC approved for recovery through the rider in 2016, was due to recovering the costs of energy from New Mexico Wind through the rider, rather than through the FPPAC in compliance with the NMPRC’s order in PNM’s NM 2015 Rate Case. The 2017 rider adjustment was approved$10.8 million and $21.7 million in the November 23, 2016 order that approvedthree and six months ended June 30, 2018 and $12.2 million and $24.4 million in the 2017 renewable energy plan. On February 28, 2017, PNM filed a reconciliation of 2017 revenue requirementthree and proposed a revision to the rider that would recover $42.7 million duringsix months ended June 30, 2017. In its 20182019 renewable energy procurement plan case, PNM proposesproposed to collect $43.5$49.6 million.
Under the renewable rider, if PNM’s earned rate of return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM is required to refund the excess to customers during May through December of the following year. PNM’s annual compliance filings with the NMPRC show that its rate of return on jurisdictional equity did not exceed the limitation through 2016.2017.

Energy Efficiency and Load Management

Program Costs and IncentivesIncentives/Disincentives

Public utilities are required by theThe New Mexico Efficient Use of Energy Act (“EUEA”) requires public utilities to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. The actEUEA requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. The NMPRC has adopted a rule to implement this act. The EUEA sets 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.

On April 15, 2016, PNM filed an application for energy efficiency and load management programs to be offered in 2017. The proposed program portfolio consisted of ten programs with a total budget of $28.0 million. The application also sought approval of an incentive of $2.4 million based on targeted savings of 75 GWh. The actual incentive would be based on actual savings achieved. On January 11, 2017, the NMPRC approved an unopposed stipulation that established a method to ensure that funding of PNM’s energy efficiency program is equal to 3% of retail revenues, with an estimated 2017 energy efficiency funding level of $26.0 million, and approved a sliding scale profit incentive with a base level of 7.1% of program costs, equal to $1.8

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million, if PNM achieves a minimum proscribed level of energy savings, increasing to a maximum of 9.0% depending on actual energy savings achieved above the minimum. On April 13, 2018, PNM filed its reconciliation of 2017 program costs and incentives, which indicated the incentive earned in 2017 is $2.3 million. The reconciliation filing and related incentive were approved on May 23, 2018.

On April 14, 2017, PNM filed an application for energy efficiency and load management programs to be offered in 2018. The proposed program portfolio consists of a continuation of the ten programs approved in the 2016 application with a total budget of $25.1 million. The application also seekssought approval of a sliding scale incentive with a base incentive of $1.9 million if PNM is able to achieve savingsavings of 53 GWh in 2018. As proposed, PNM would have earned an incentive of $2.1 million based on targeted savings of 70 GWh. The actual incentive would be based on actual savings achieved. PNM proposed to continue the same ten programs and a similar incentive mechanism in 2019, with a proposed budget of $28.2 million and a base level incentive of $2.1 million. On July 26, 2017, PNM, NMPRC staff, and other parties filed a stipulation that would resolve all issues in the case if approved by the NMPRC. Under the settlement, terms, all of PNM’s proposed programs would be approved with limited modifications and PNM’s base level incentive would be $1.7 million in 2018. PNM would earn an incentive of $1.9 million based on targeted savings of 69 GWh. A public hearing was held in September 2017. PNM is unableOn November 8, 2017, the Hearing Examiner issued a Certification of Stipulation recommending approval of the stipulation with various modifications, including adoption of a discount rate equal to predict the outcometax-adjusted WACC of this proceeding.9.59% rather than the 7.71% proposed in the stipulation and modifying the program budgets to $23.6 million for 2018 and $24.9 million for 2019. On January 31, 2018, the NMPRC issued an order that largely accepted the certification with certain exceptions concerning the measurement and verification of the approved load management programs.
Energy Efficiency Rulemaking
In July 2012, the NMPRC opened an energy efficiency rulemaking docket to potentially 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 January 25, 2017, the NMPRC opened another energy efficiency rulemaking docket to consider whether applications

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for approval of energy efficiency and load management programs should be filed every two years rather than annually. Written comments were filed in the rulemaking docket, and a public comment hearing was held on March 31, 2017. On June 21, 2017, the NMPRC issued an order that modifies the filing frequency for utility energy efficiency plans to every three years.
Also onOn June 21, 2017, the NMPRC also issued a new notice of proposed rulemaking to consider possible changes affecting a utility’s ability to modify NMPRC approved funding levels by up to 10% between energy efficiency program applications. This rulemaking is in response to consensus changes proposed by parties in the January 25, 2017 rulemaking. On September 13, 2017, the NMPRC approved the proposed rule. Under the new rule, PNM’s next application for energy efficiency and load management programs will be made in 2020 for programs to be offered beginning in 2021.

Petition for Energy Efficiency Disincentive

As discussed above, PNM’s December 2016 application in the NM 2016 Rate Case had requested a “lost contribution to fixed cost” mechanism to address the disincentives associated with PNM’s energy efficiency programs. In the revised stipulation to that case, PNM agreed to withdraw its proposal for such a mechanism and to address energy efficiency disincentives in a future docket. On March 2, 2018, PNM filed a petition proposing a “lost contribution to fixed cost mechanism” with substantially the same terms as those proposed in the NM 2016 Rate Case application. The Hearing Examiner for this matter has issued a procedural order that includes a public hearing to begin on October 30, 2018.

FPPAC Continuation Application
NMPRC rules require public utilities to file an application to continue using their FPPAC every four years. On April 23, 2018, PNM filed the required continuation application and requested that its FPPAC be continued without modification. On June 20, 2018, the NMPRC approved PNM’s continuation application.

Integrated Resource Plans
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.
2014 IRP
PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term resource needs 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 to not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the then 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 asserted that the 2014 IRP did not conform to the NMPRC’s IRP rule. Certain parties also asked that further proceedings on the 2014 IRP be held in abeyance until the conclusion of the SJGS abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that docketed a case to determine whether the 2014 IRP complied with applicable NMPRC rules. The order also held 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 order regarding PNM’s application to abandon SJGS Units 2 and 3 described in Note 11 states that the NMPRC will issue a Notice of Proposed Dismissal in the 2014 IRP docket. On May 4, 2016, the NMPRC issued the Notice of Proposed Dismissal, stating that the docket would be closed with prejudice within thirty days unless good cause was shown why the docket should remain open. On May 31, 2016, NEE filed a request to hold the protests filed against PNM’s 2014 IRP in abeyance or to dismiss those protests without prejudice. PNM resp

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ondedresponded on June 13, 2016 and requested that the NMPRC dismiss the case with prejudice. The NMPRC has not yet acted on its Notice of Proposed Dismissal or the request filed on May 31, 2016. PNM cannot predict the outcome of this matter.

2017 IRP

PNM filed its 2017 IRP on July 3, 2017. The 2017 IRP addresses athe 20-year planning period from 2017 through 2036 and includes an action plan describing PNM’s plan to implement the 2017 IRP in the four-year period following its filing. PNM held its initial public advisory meeting on the 2017 IRP on June 30, 2016 and hosted 17 meetings statewide to present details of

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the process and receive public comment. The NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 11 requires PNM to make a filing in 2018 to determine the extent to which SJGS Units 1 and 4 should continue serving PNM’s retail customers’ needs after June 30, 2022. The 2017 IRP analyzed several scenarios utilizing assumptions that PNM continues service from its SJGS capacity beyond mid-2022 and that PNM retires its capacity after mid-2022. Key findings of the 2017 IRP include:

Retiring PNM’s share of SJGS in 2022 after the expiration of the current operating and coal supply agreements would provide long-term cost savings for PNM’s customers
PNM exiting its ownership interest in Four Corners after its current coal supply agreement expires in 2031 would also save customers money
The best mix of new resources to replace the retired coal generation would include solar energy and flexible natural gas-fired peaking capacity; the mix could include energy storage, if the economics support it, and wind energy provided additional transmission capacity becomes available
Significant increases in future wind energy supplies will likely require new transmission capacity to be built from eastern New Mexico to PNM’s service territory
PNM should retain the currently leased capacity in PVNGS, which would avoid replacement with carbon-emitting generation
PNM should continue to develop and implement energy efficiency and demand management programs
PNM should assess the costs and benefits of participating in the California Energy Imbalance Market
PNM should analyze its current Reeves Generating Station to consider possible technology improvements to phase out the older generators and replace them with new, more flexible supplies or energy storage

Protests to the 2017 IRP were filed by several parties. The issues addressed in the protests included the future of PNM’s interests in SJGS, Four Corners, and PVNGS and the timing of future procurement of renewable resources. The NMPRC has assignedOn January 16, 2018, the case to a Hearing Examiner and a briefing schedule has been established to determineissued an order setting the appropriate scope of the case.proceedings as the 2017 IRP’s compliance with applicable statute and NMPRC rules. On February 22, 2018, PNM provided certain underlying information and clarified how costs, transmission constraints, energy storage, and public input were considered in developing the 2017 IRP. Hearings began on June 4, 2018 and concluded on June 12, 2018.

The 2017 IRP is not a final determination of PNM’s future generation portfolio. Retiring PNM’s share of SJGS capacity and exiting Four Corners would require NMPRC approval of abandonment filings, which PNM would make at appropriate times in the future. Likewise, NMPRC approval of new generation resources through CCN filings would be required. PNM cannot predict the ultimate outcome of the 2017 IRP process or whether the NMPRC will approve subsequent filings that would encompass actions to implement the conclusions of the 2017 IRP.

San Juan Generating Station Units 2 and 3 Retirement
On December 16, 2015, the NMPRC issued an order approving PNM’s retirement of SJGS Units 2 and 3 on December 31, 2017. On January 14, 2016, NEE filed an appeal of the order with the NM Supreme Court. SJGS Units 2 and 3 were retired in December 2017. On March 5, 2018, the NM Supreme Court rendered a decision affirming the NMPRC’s ruling, thereby denying NEE’s appeal. A request for rehearing of the NM Supreme Court’s decision was not filed by the statutory deadline. This matter is now concluded. Additional information concerning the NMPRC filing and related proceedings is set forth in Note 11.
ApplicationSan Juan Generating Station Unit 1 Outage
On March 17, 2018, a coal silo used to supply fuel to SJGS Unit 1 collapsed resulting in an outage. PNM initiated a review of the cause of the outage and promptly contacted the staff of the NMPRC to inform them of the event. To minimize the operational and financial impacts of this event, PNM accelerated the fall 2018 planned outage to be performed while the unit was out of service for Certificatethis event. Repairs necessary to return Unit 1 to service were completed by July 5, 2018. PNM anticipates the damages to the facility will be reimbursed under an existing property insurance policy that covers SJGS, subject to a deductible of Convenience and Necessity

$2.0 million.  PNM’s exposure to the cost of repairs is $1.0 million, reflecting PNM’s 50% ownership interest in SJGS Unit 1.
On April 26, 2016, PNM filed an application for an 80 MW gas plant to be located at SJGS, with an anticipated June12, 2018, in-service date. On October 13, 2016, PNMNEE filed a motion to vacatepetition (jointly with certain other organizations) requesting that the procedural schedule to allowNMPRC order an investigation into the SJGS Unit 1 event.  The petition requested that the NMPRC order PNM to assessrespond to the continued need for the plant in light of possible changed circumstances affecting loads and resources. On October 28, 2016, PNM filed a motion to withdraw its application and close the docket. As grounds for the motion, PNM statedpetition, that based on its updated peak demand forecast, the 80 MW plant would not be needed in 2018. On December 1, 2016, the Hearing Examiner issued a

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)


recommended decisionproceedings be set on this matter, and that would grant PNM’s motionPNM be required to withdraw its application.provide a narrative explanation, cost/benefit analysis, and alternatives assessment used to determine that Unit 1 should be repaired rather than utilizing alternative resources.  On May 24, 2017,April 25, 2018, the NMPRC issued an order requiring PNM to provide a factual statement of the nature and cause of the event, as well as the anticipated need for and schedule of repairs required. PNM was also required to address the necessity and appropriateness of the request for a cost/benefit analysis, alternatives assessment, and request for further proceedings. On May 8, 2018, PNM filed its response to the NMPRC order approvingindicating that PNM used best practices when inspecting the SJGS coal silos during planned outages, that the damage to SJGS Unit 1 was repairable and could be made in a timely manner, that all but a limited amount of cost of the repairs are reimbursable under an existing insurance policy, and that further proceedings on the matter were unnecessary. In addition, PNM’s response indicated that if the unit was not repaired, customers would be exposed to significant contractual liabilities under the agreements governing the ownership of SJGS and would incur significant costs associated with the procurement of replacement power. On May 31, 2018, the NMPRC staff preliminarily recommended decisionthat the NMPRC not allow PNM to recover any costs associated with the SJGS Unit 1 coal silo repairs, including the cost of preventing similar failures on other SJGS coal silos, and grantingthat PNM reimburse customers for the loss of off-system sales during the time SJGS Unit 1 was in outage. The NMPRC staff also recommended, among other things, that further proceedings on the matter be deemed unnecessary provided PNM agree to hold customers harmless for such costs. On June 15, 2018, PNM filed a motion requesting the NMPRC extend the deadline for PNM’s response to withdrawstaff’s preliminary recommendation until August 17, 2018. The NMPRC has not yet acted on this motion. PNM cannot predict the application. PNM will continue to evaluate its resource needs as partoutcome of its ongoing resource planning activities.this event.

Advanced Metering Infrastructure Application

On February 26, 2016, PNM filed an application with the NMPRC requesting approval of a project to replace its existing customer metering equipment with Advanced Metering Infrastructure (“AMI”). The application asksasked the NMPRC to authorize the recovery of the cost of the project, up to $87.2 million, in future ratemaking proceedings, as well as to approve the recovery of the remaining undepreciated investment in existing metering equipment estimated to be approximately $33 million at the date of implementation, and the costs of customer education, and severances for affected employees. On August 5, 2016, PNM filed a motion to suspend its AMI application so that it could evaluate the effect of the order in the NM 2015 Rate Case. The NMPRC approved this motion. On November 22, 2016, PNM filed a motion to lift the suspension and establish a new procedural schedule. In December 2016, the Hearing Examiner issued an order lifting the suspension and issued a new procedural schedule. Hearings in this matter were held in February and March 2017. During the March 2017 hearing, it was disclosed that the proposed meter contractor may not have complied with certain New Mexico contractor licensing requirements. PNM subsequently filed testimony regarding that matter as ordered by the Hearing Examiner. On May 12, 2017, PNMand requested a new procedural schedule to allow itthat allowed PNM to issue a new RFP for contracting work related to the meter installation and to update its cost-benefit analysis. PNM subsequently updated the amount of the requested recovery for the anticipated cost of the project to $95.1 million. An additional hearing was held on October 25-26, 2017. On March 19, 2018, the Hearing Examiner issued a recommended decision finding that PNM doeshad not intendproven a net public benefit in the case and recommending the NMPRC not approve the application. On April 2, 2018, PNM filed a statement on exceptions to proceedthe recommended decision indicating, among other things, that PNM disagreed with the AMI project unlessfinding that the record did not demonstrate a net public benefit to customers, but that PNM would not take exception to a recommendation to not approve the application. No other parties filed exceptions to the recommended decision by the required deadline. On April 11, 2018, the NMPRC approvesadopted an order accepting the entirerecommended decision and disapproving PNM’s application. PNM cannot predict the outcome of this matter.The order indicated PNM’s next energy efficiency plan filing should include a proposal for an AMI pilot project.

Facebook, Inc. Data Center Project

On July 8, 2016, PNM filed an application withAs discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K, the NMPRC approved a PNM application for approval of:arrangements in connection with services to be provided to Facebook, Inc. for a new data center to be constructed in PNM’s service area. The approvals included:

Two new electric service rates
A PPA under which PNM would purchase renewable energy from PNMR Development
A special service contract to provide electric service to a prospective new customer, a large Internet company, that was considering locating a data center in PNM’s service area
The NMPRC approved PNM’s application on August 17, 2016. At that time, the new customer was also considering the state of Utah for the location of the data center. On September 15, 2016, PNM filed a notice informing the NMPRC that the customer, Facebook, Inc., had announced that it was selecting a site in New Mexico for its new data center.
Facebook’s service requirements include the acquisition by PNM of a sufficient amount of new renewable energy resources and RECs to match the energy and capacity requirements of the data center. PNM’s initial procurement willwas to be through a PPA with PNMR Development for the energy production from 30 MW of new solar capacity that PNMR Development will constructwas to construct. As discussed in Note 1, PNMR Development transferred its interests in the solar capacity and own.the PPA to NMRD in December 2017. The cost of the PPA will beis passed through to Facebook under a new rate rider. A new special service rate will beis applied to Facebook’s energy consumption in those hours of the month when their consumption exceeds the energy production from the new renewable resources. Construction ofOf the firstsolar capacity, 10 MW began commercial operation in each of solar capacity is expected to be completed in earlyJanuary 2018, which will coincide with initial operations of the data center, with the remainder of the capacity completed by mid-2018.
The approval order included a provision requiring that in any future rate case filed by PNM requesting an increase in rates of any other customer class, the NMPRC shall determine whether or not any customer class will be subject to increased rates due to Facebook’s fixed “Contribution to Production Charge for System Supplied Energy”March 2018, and if so, the NMPRC shall determine whether or not PNM will be allowed to recover such increased costs in the form of increased rates to other customers. In the NM 2016 Rate Case filing discussed above, PNM indicated the Facebook arrangement did not result in increased rates to any other customer class.
Hazard Sharing Agreements
On June 1, 2016, PNM and Tri-State entered into a one-year hazard sharing agreement, which expired on May 31, 2017.  PNM and Tri-State entered into an additional agreement, under substantially identical terms, for a term of five years beginning2018.

PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


June 1,
In late 2017, PNM entered into three separate 25-year PPAs to purchase renewable energy and RECs to be used by PNM to supply additional renewable energy to Facebook. These PPAs were subject to NMPRC approval.approval and PNM made a filing requesting approval on January 17, 2018. A NMPRC approvalhearing on PNM’s filing was not required for the one-year agreement, but was required for the five-year agreement. On May 10, 2017,held on March 7, 2018 and the NMPRC issued an order approvingapproved the five-year agreement.PPAs on March 21, 2018. These PPAs include the purchase of the power and RECs from:
Under these agreements, each party sells the other party 100 MW
Casa Mesa Wind, LLC, a subsidiary of capacity and energy from each party’s designated primary resources,NextEra Energy Resources, LLC., which is SJGS Unit 4 for PNMexpected to be located near House, New Mexico, have a total capacity of 50 MW, and Springerville Generating Station Unit 3 for Tri-State,be operational on December 31, 2018
A 166 MW portion of the La Joya Wind Project, owned by Avangrid Renewables, LLC, which is expected to be located near Estancia, New Mexico and be operational in November 2020
Route 66 Solar Energy Center, LLC, a unit contingent basis subjectsubsidiary of NextEra Energy Resources, LLC., which is expected to certain performance guarantees.  The agreements reduce the magnitudebe located west of each party’s single largest generating hazardAlbuquerque, New Mexico, have a total capacity of 50 MW, and assistbe operational in enhancing the reliability and efficiency of their respective operations. Both purchases and sales are made at the same market index price. PNM passes the sales and purchases through to customers under PNM’s FPPAC.  Information about the purchases and sales is as follows:December 2021
 Sales Purchases
 GWh Amount GWh Amount
   (In millions)   (In millions)
        
Three months ended September 30, 2017202.4
 $7.2
 215.1
 $7.6
Three months ended September 30, 2016208.2
 6.2
 216.4
 6.4
        
Nine months ended September 30, 2017615.0
 17.7
 632.5
 18.2
Nine months ended September 30, 2016268.5
 7.8
 278.8
 8.1

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

AsTNMP 2018 Rate Case

On May 30, 2018, TNMP filed a general rate proceeding with the PUCT (the “TNMP 2018 Rate Case”), which requests an annual increase to base rates of $25.9 million based on a requested ROE of 10.5% and a capital structure comprised of 50% debt and 50% equity. TNMP’s request includes $7.7 million of new rate riders to recover Hurricane Harvey restoration and additional vegetation management costs. The application includes the integration of revenues currently recorded under the AMS rider and collection of other unrecovered AMS investments into base rates. In 2017, TNMP recorded revenues of $21.8 million under the AMS rider. The TNMP 2018 Rate Case application also proposes to return the regulatory liability recorded at December 31, 2017 related to tax reform to customers and to reduce the federal corporate income tax rate to 21%. At December 31, 2017, TNMP recorded a regulatory liability of $146.5 million to reflect the change in federal corporate income tax rates that will be refunded to customers in future periods, as discussed in Note 1711 of the Notes to the Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K, NEC filed10-K. The TNMP 2018 Rate Case application proposes to refund $14.4 million of this regulatory liability over a petition on April 8, 2015 for a declaratory order requesting that FERC find that NEC could purchase an unlimitedperiod of five years and the remaining amount over the estimated useful lives of power and energy from third party supplier(s) under its PSA with PNM. 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. FERC approved the settlement on January 21, 2016. Under the settlement agreement, PNM served allplant in service as of NEC’s load in 2016 at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC also paid certain third-party transmission costs that it only partially paid previously. The PSA and related transmission agreements terminated on December 31, 2016. In 2017, PNM2017. If approved by the PUCT, new rates are expected to become effective in early 2019. A hearing is serving 10 MWcurrently scheduled to begin September 7, 2018. TNMP cannot predict the outcome of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. Amounts billed to NEC were $1.1 million and $4.8 million in the three months ended September 30, 2017 and 2016 and $3.3 million and $14.8 million in the nine months ended September 30, 2017 and 2016. PNM’s NM 2016 Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve NEC.this matter.
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. TNMP completed its mass deployment in 2016 and has installed more than 242,000 advanced meters. The TNMP 2018 Rate Case discussed above, which was filed on May 30, 2018, includes a reconciliation of AMS costs and a request to integrate AMS recovery into base rates.
The PUCT adopted a rule 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. As approved by the PUCT, TNMP is recovering $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million through a $36.78 monthly fee. These amounts presume up to 1,081 consumers will elect the non-standard meter service, but TNMP has the right to adjust the fees if the number of anticipated consumers differs from that estimate. As of October 20, 2017, 99July 25, 2018, 97 consumers 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.


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)


Transmission Cost of Service Rates
TNMP can update its transmission rates twice per year to reflect changes in its invested capital.capital although updates are not allowed while a general rate case is in process. 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 recent interim transmission cost rate increases:

Effective Date Approved Increase in Rate Base Annual Increase in Revenue
  (In millions)
September 10, 2015 $7.0
 $1.4
March 23, 2016 25.8
 4.3
September 8, 2016 9.5
 1.8
March 14, 2017 30.2
 4.8
September 13, 2017 27.5
 4.7
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


On March 23, 2017, the PUCT staff filed proposed amendments to the interim transmission cost of service filing rule. If approved, the amendments could reduce the frequency of such filings to once per year. The amendments could also reduce the amount recovered by requiring that changes in accumulated deferred income taxes be considered and would preclude filings by utilities earning more than their authorized rate of return using weather-normalized data. The PUCT has not yet approved the amendments for publication. Initial comments on the proposed rule will be due 30 days after publication. TNMP cannot predict the outcome of this matter.
Effective Date Approved Increase in Rate Base Annual Increase in Revenue
  (In millions)
September 8, 2016 $9.5
 $1.8
March 14, 2017 30.2
 4.8
September 13, 2017 27.5
 4.7
March 27, 2018 32.0
 0.6

Periodic Distribution Rate Adjustment

PUCT rules permit interim rate adjustments to reflect changes in investments in distribution assets. Distribution utilities may file for a periodic rate adjustment between April 1 and April 8 of each year as long as the electric utility is not earning more than its authorized rate of return using weather-normalized data. However, TNMP has not made a filing to adjust rates for additional investments in distribution assets. In connection with TNMP’s deployment of its advanceadvanced meter system discussed above, TNMP committed to file a general rate case no later than September 1, 2018. TNMP has also committed that it would not file a request for an increase in rates to reflect changes in investments in distribution assets until after the effective date of final order in the TNMP 2018 general rate case.Rate Case.

Competition Transition Charge Compliance FilingOrder Related to Changes in Federal Income Tax Rates

On January 25, 2018, the PUCT issued an accounting order that addresses the change in the federal corporate income tax rates on investor-owned utilities in the state of Texas. The order requires investor-owned utilities to record a regulatory liability equal to the reduction in accumulated federal deferred income tax balances at the end of 2017 due to the change in the federal corporate income tax rate. In connectionaddition, the order requires that a regulatory liability be recorded to reflect the difference between revenues collected under existing rates and those that would have been collected had those rates been set reflecting federal income tax reform beginning on the date of the order (Note 14). In compliance with the adoptionPUCT order, during the three and six months ended June 30, 2018, TNMP reduced revenues by $1.2 million and $2.7 million and recorded these as a regulatory liability to reflect the impact of legislationthe reduction in the federal corporate tax rate beginning January 25, 2018. The January 25, 2018 order provides that deregulated electric utilities operating within ERCOT,the regulatory liabilities will be considered by the PUCT in each utility’s next rate proceeding, which for TNMP was allowedfiled on May 30, 2018. TNMP believes the PUCT order constitutes retroactive ratemaking as it relates to recover its stranded coststhe requirement to record a regulatory liability for revenues collected beginning January 25, 2018. Accordingly, the TNMP 2018 Rate Case discussed above does not include a refund to customers for the reduction in the federal corporate income tax rate for the period from January 25, 2018 through the CTC and to also recover a carrying charge oneffective date of new rates. TNMP cannot predict the CTC. Further, the order authorizing TNMP's CTC included a true-up provision requiring an adjustment to the CTC due to a cumulative over- or under-collectionoutcome of revenues, including interest, greater-than or equal to 15% of the most recent annual CTC funding amount. On March 13, 2017, TNMP made a filing to true-up the CTC. The requested adjustment reduces the collection of the amortization by $1.1 million annually. On April 3, 2017, the PUCT staff filed its recommendation to approve the requested adjustment. The change was approved on April 5, 2017 and went into effect on June 1, 2017.this matter.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor (“EECRF”), which includes projected program costs, under orand over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed mandated savings goals). On May 25, 2017,30, 2018, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2018.2019. The total amount requested was $6.0is $5.7 million, which includedincludes a performance bonus of $1.1$0.9 million based on TNMP’s energy efficiency achievements in the 20162017 plan year. On September 28, 2017,June 21, 2018, the PUCT approvedissued a settlement amongdeclaratory order announcing the parties accepting TNMP’s filing without adjustment.PUCT’s interpretation of the bonus calculation in its rule. The order does not affect cost recovery but reduces the bonus calculation as filed by utilities in their current EECRF proceedings. Accordingly, as of June 30, 2018, TNMP reduced its estimated performance bonus for the 2017 plan year to $0.8 million. A hearing is scheduled for August 17, 2018.

(13)Lease Commitments

The Company leases office buildings, vehicles, and other equipment. In addition, PNM leases interests in Units 1 and 2 of PVNGS and certain right-of-way agreements are classified as leases. All of the Company’s leases are currently accounted for as operating leases. See New Accounting Pronouncements in Note 1. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K, including PNM’s actions with regard to renewal and purchase options 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

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)


extended to expire on January 15, 2024. For the other three PVNGS Unit 2 leases, PNM exercised its fair market value options to purchase the assets underlying those leases on the expiration date of the original leases. On January 15, 2016, PNM paid $78.1 million to the lessor under one lease for 31.25 MW of the entitlement from PVNGS Unit 2 and $85.2 million to the lessors under the other two leases for 32.76 MW of the entitlement from PVNGS Unit 2. See Note 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case.

PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, 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 lessors, and take title to the leased interests. If such an event had occurred as of June 30, 2018, amounts due to the lessors under the circumstances described above would be up to $166.8 million, payable on July 15, 2018 in addition to the scheduled lease payments due on July 15, 2018.

(14)Income Taxes

On December 22, 2017, comprehensive changes in United States federal income taxes were enacted through legislation commonly known as the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act makes many significant modifications to the tax laws, including reducing the federal corporate income tax rate from 35% to 21% effective January 1, 2018. The Tax Act also eliminates federal bonus depreciation for utilities effective September 28, 2017 and, effective January 1, 2018, limits interest deductibility for non-utility businesses and limits the deductibility of certain officer compensation.

Although most of the provisions of the Tax Act are not effective until 2018, GAAP required that some effects be recognized in 2017. Under the asset and liability method of accounting for income taxes used by the Company, deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. The deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to reverse. At the date of enactment of the Tax Act, the Company had net deferred tax liabilities for its regulated activities and net deferred tax assets for non-regulated activities. As a result of the change in the federal corporate income tax rate, the Company re-measured and adjusted its deferred tax assets and liabilities as of December 31, 2017. The portion of that adjustment not related to PNM’s and TNMP’s regulated activities was recorded as a reduction in net deferred tax assets and an increase in income tax expense. The portion related to PNM’s and TNMP’s regulated activities was recorded as a reduction in net deferred tax liabilities and an increase in regulatory liabilities, based on the assumption that PNM and TNMP will be required to return the benefit to ratepayers over time. PNM’s NM 2016 Rate Case (Note 12) reflects that assumption by including an amortization of the estimated benefit of the reduction in existing deferred federal corporate income taxes as a reduction to customer rates over a twenty-one year period beginning in 2018. On January 25, 2018, the PUCT issued an order requiring Texas utilities, including TNMP, to begin recording regulatory liabilities for the effects of the Tax Act with the stated purpose of reflecting those effects in the utility bills of Texas ratepayers. During the three and six months ended June 30, 2018, TNMP reduced revenue and recorded a regulatory liability of $1.2 million and $2.7 million in accordance with the PUCT’s order. The TNMP 2018 Rate Case filed on May 30, 2018, includes a reduction in customer rates to reflect the impacts of the Tax Act, including amortization of the regulatory liability related to the 2017 re-measurement of deferred tax liabilities and to reduce the federal corporate income tax rate to 21% (Note 12).

In December 2017, the SEC issued Staff Accounting Bulletin No. 118, which provides guidance to address the application of GAAP to reflect the Tax Act in circumstances where all information and analysis of the Tax Act is not yet available or complete. This bulletin provides for up to a one-year period in which to complete the required analyses and accounting for the impacts of the Tax Act. The Company believes it made reasonable estimates of the effects of the Tax Act and reflected the impacts in the Consolidated Financial Statements included in the 2017 Annual Reports on Form 10-K. However, the reported effects on the Company’s deferred tax assets and liabilities, regulatory assets and liabilities, and income tax expense are provisional and it is possible that changes to United States Treasury regulations, IRS interpretations of the provisions of the Tax Act, actions by the NMPRC, PUCT, and FERC, or the Company’s further analysis of historical records could cause these estimates to change. Through June 30, 2018, no significant adjustments to the impacts reflected in the 2017 Consolidated Financial Statements included in the 2017 Annual Reports on Form 10-K have been identified.

In 2013, New Mexico House Bill 641 reduced 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, which was in the year ended December 31, 2013. At that time, the portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities and an increase in a regulatory liability, based on the assumption that PNM would be required to return the benefit to customers over time. PNM’s NM 2016 Rate Case (Note 12) reflects the benefit of the

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)


lower New Mexico corporate income taxes during the period that includes the date of enactment, which was in the year ended December 31, 2013, to reflect the tax rate at which the balances are expected to reverse. At that time, the portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM would be required to return the benefitbeing returned to customers over time.a three-year period beginning February 1, 2018. In addition, the portion of the adjustment that iswas 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 resultresulted in refinements of the impacts of this change in tax rates being recorded periodically until 2018, whenthrough December 31, 2017, at which time the impacts of the rate reduction iswere fully phased in.phased-in. In the three months ended March 31, 2017, and 2016, PNM’s regulatory liability was reduced by $4.8 million and $7.1 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were:were reduced by $0.1 million in the three months ended March 31, 2017, increasing income tax expense by less than $0.1 million for PNM and $0.1 million for the Corporate and Other segment; and decreased by $0.7 million insegment.

As required under GAAP, the three months ended March 31, 2016, increasingCompany makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. In interim periods, income tax expense is calculated by $0.8 million forapplying the anticipated annual effective tax rate to year-to-date earnings before income taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, including excess tax benefits related to stock awards, be excluded from the estimated annual effective tax rate calculation. At June 30, 2018, PNMR, PNM, and reducingTNMP estimated their effective income tax expense by $0.1 millionrates for the Corporateyear ended December 31, 2018 would be 12.47%, 9.08%, and Other segment. In23.00%. These rates reflect the stipulation filed in PNM’s NM 2016 Rate Case (Note 12), it is proposed that the benefit of the lower New Mexicoreduced federal corporate income tax rate be returnedof 21%, which rates are adjusted to customers over a three-year period beginning January 1, 2018.

In 2008, fifty percent bonus tax depreciation was enacted as a temporary two-year stimulus measure as part of the Economic Stimulus Act of 2008. Bonus tax depreciationreflect permanent differences between earnings determined in various forms has been continuously extended since that time. As a result of the net operating loss carryforwards for income tax purposes created by bonus depreciation, and reduced future income taxes payable resulting from New Mexico House Bill 641, certain tax carryforwards are not expected to be utilized before their expiration. In accordance with GAAP PNMR and PNM have impairedtaxable income, as well as state income taxes. The primary permanent difference is the tax carryforwards which were not expected to be utilized prior to their expiration. The Company has not recorded any impairmentsreduction in 2016 or 2017. The NMPRC’s final order in PNM’s NM 2015 Rate Case (Note 12) approved PNM’s request to record a regulatory asset to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from the extension of bonus depreciation. The impact, net of federal income taxes, amounts to $2.1 million, which is reflected as a reduction of income tax expense on the Condensed Consolidated Statement of Earnings in the three months ended September 30, 2016.

The Company undertook an analysis of interest income and interest expense applicable to federal income tax matters. The analysis encompassed the impacts of IRS examinations, amended income tax returns, and filings for carrybacks of tax matters to previous taxable years applicable to all years not closed under the IRS rules. As a result of this effort, PNMR received net refunds from the IRS of $6.5 million in the three months ended June 30, 2016. Of the refunds, $2.1 million was recorded as a reduction of interest receivable and $5.1 million was recorded as interest income, which was partially offset by $0.7 million of interest expense. In addition, PNMR incurred $0.9 million in professional fees related to the analysis. Of the net pre-tax impacts aggregating $3.5 million, $2.6 million is reflected in the PNM segment, $0.3 million in the TNMP segment, and $0.6 million in the Corporate and Other segment.

See Note 8 for a discussion of the impacts on income tax expense resulting from the adoptionamortization of Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718).

excess deferred federal and state income taxes ordered by the NMPRC in PNM’s NM 2016 Rate Case. During the three and six months ended June 30, 2018, income tax expense calculated by applying the expected annual effective income tax rate to earnings before income taxes was further reduced by excess tax benefits related to stock awards of $0.1 million and $1.4 million for PNMR, less than $0.1 million and $1.0 million for PNM, and less than $0.1 million and $0.3 million for TNMP.

(14)(15)Related Party Transactions

PNMR, PNM, TNMP, and TNMPNMRD are considered related parties as defined under GAAP, as is PNMR Services Company, a wholly-owned subsidiary of PNMR that provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. In addition, PNMR provides construction and operations and maintenance services to NMRD, a 50% owned subsidiary of PNMR Development (Note 1), and PNM purchases renewable energy from certain NMRD-owned facilities at a fixed price per MWh of energy produced. PNM also provides interconnection services to PNMR Development (Note 9) and NMRD. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and TNMP:NMRD:
 Three Months Ended Six Months Ended
 June 30, June 30,
 2018 2017 2018 2017
 (In thousands)
Services billings:       
PNMR to PNM$22,471
 $23,190
 $46,150
 $47,593
PNMR to TNMP8,058
 7,806
 16,423
 15,943
PNM to TNMP90
 102
 177
 187
TNMP to PNMR35
 35
 70
 70
TNMP to PNM—
 57
 —
 145
PNMR to NMRD51
 —
 130
 —
Renewable energy purchases:       
PNM from NMRD1,004
 —
 1,374
 —
Interconnection billings:       
PNM to NMRD2,052
 —
 2,052
 —
PNM to PNMR68,200
 —
 68,200
 —
Interest billings:       
PNMR to PNM747
 9
 809
 11
PNM to PNMR70
 49
 136
 92
PNMR to TNMP13
 30
 22
 60
Income tax sharing payments:       
PNMR to PNM—
 —
 —
 —
TNMP to PNMR—
 —
 —
 —

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)


 Three Months Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (In thousands)
Services billings:       
PNMR to PNM$23,451
 $22,189
 $71,044
 $67,192
PNMR to TNMP7,828
 6,593
 23,771
 20,881
PNM to TNMP115
 105
 302
 347
TNMP to PNMR35
 10
 106
 30
TNMP to PNM8
 84
 154
 171
Interest billings:       
PNMR to TNMP66
 13
 126
 112
PNMR to PNM3
 3
 14
 8
PNM to PNMR71
 38
 163
 110
Income tax sharing payments:       
PNMR to PNM—
 —
 —
 —
PNMR to TNMP—
 —
 —
 —

(15)(16)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. PNMR’s reporting units that currently have goodwill are PNM and TNMP. Additional information concerning the Company’s goodwill is contained in Note 18 of Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K.

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. 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 has 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. An entity places more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also 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. A quantitative analysis is not required 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.

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. 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. 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, GAAP currently requires the entity 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

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)


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. As further discussed under New Accounting Pronouncements in Note 1, a new accounting pronouncement changes how a goodwill impairment is determined by eliminating the second step of the quantitative impairment analysis.

For its annual evaluations performed as of April 1, 2016, PNMR performed quantitative analyses for both the PNM and TNMP reporting units. For the quantitative analyses, 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 April 1, 2016 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%. The April 1, 2016 quantitative evaluation indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 32%.

For its annual evaluations performed as of April 1, 2017, PNMR performed qualitative analyses for both the PNM and TNMP reporting units. The qualitative analysis was performed by considering changes in the Company’s expectations of future financial performance since the April 1, 2016 quantitative analysis. This analysis considered Company specific events such as the potential impacts of legal and regulatory matters discussed in Note 11 and Note 12, including the then estimated impacts of the proposed revised stipulation in PNM’s NM 2016 Rate Case, the impacts of potential outcomes of the matters appealed to the NM Supreme Court under the NM 2015 Rate Case, and the impacts of changes in PNM’s resource needs based on PNM’s 2017 IRP. This evaluation also considered changes in TNMP’s regulatory environment such as the PUCT’s then proposed amendments to the interim transmission cost of service filing rule, as well as potential outcomes associated with TNMP’s anticipated general rate case filing, which the Company anticipates filing in 2018.filing. The qualitative analysis also considered market and macroeconomic factors including changes in anticipated growth rates, anticipatedchanges in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying value of its reporting units. Based on an evaluation of these and other factors, the Company determined it was not more likely than not that the April 1, 2017 carrying values of PNM or TNMP exceeded their fair values.


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 its annual evaluations performed as of April 1, 2018, PNMR performed a quantitative analysis for the PNM reporting unit and a qualitative analysis for the TNMP reporting unit. For the quantitative analyses, a discounted cash flow methodology was primarily used to estimate the fair value of the PNM 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 the reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. The April 1, 2018 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 19%. The 2018 qualitative analysis for the TNMP reporting unit was performed by considering changes in expectations of future financial performance since the April 1, 2016 quantitative analysis that indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 32% and the April 1, 2017 qualitative analysis. The 2018 analysis considered events specific to TNMP such as the potential impacts of legal and regulatory matters discussed in Note 12, including potential adverse outcomes in the TNMP 2018 Rate Case, which was filed in May 2018. Both the PNM quantitative analysis and the TNMP qualitative analysis considered market and macroeconomic factors including changes in growth rates, changes in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying value of its reporting units. Based on an evaluation of these and other factors, the Company determined it is not more likely than not that the April 1, 20172018 carrying values of PNM or TNMP exceed their fair values.

As indicated above, the annual evaluations performed as of April 1, 20172018 and 20162017 did not indicate impairments of the goodwill of any of PNMR’s reporting units. Since the April 1, 20172018 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below their carrying values.

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 772,000777,000 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 three key 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 employee safety, plant performance, and system reliability
Delivering a superior customer experience
•
Demonstrating environmental stewardship in their business operations, including reducing CO2 emissions
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 two key factors: fair and timely regulatory treatment for its utilities and the utilities’ 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.

Fair and timely rate treatment from regulators is crucial to PNM and TNMP in earning their allowed returns and critical for PNMR to achieve its strategic goals. PNMR believes that earning allowed returns would beis viewed positively by credit rating agencies and would further improvethat improvements in the Company’s ratings which could lower costs to utility customers. Also, earning allowed returns should result in increased earnings growth for PNMR.

Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K and in Note 12.

State Regulation

New Mexico 2015 Rate Case – On September 28, 2016, the NMPRC issued an order that authorized PNM to implement an increase in base non-fuel rates of $61.2 million for New Mexico retail customers, effective for bills sent after September 30, 2016. This order was on PNM’s application for a general increase in retail electric rates (the “NM 2015 Rate Case”) filed in August 2015. PNM’s application requested an increase in base non-fuel revenues of $121.5 million based on a future test year (“FTY”) beginning October 1, 2015. The primary drivers of the revenue deficiency were infrastructure investments and declines

in forecasted energy sales due to successful energy efficiency programs and other economic factors. PNM also proposed changes to rate design to provide fairer pricing across rate classes and better align cost recovery with cost causation.

Following public hearings, the Hearing Examiner in the case issued a recommended decision (“RD”) in August 2016 proposing an increase in non-fuel revenues of $41.3 million. The NMPRC’s September 26, 2016 order approved many aspects of the RD, including theincluded a determination that PNM was imprudent in purchasing the 64.1 MW of previously leased capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing BDT equipment on SJGS Units 1 and 4. However, the order also made certain significant modifications to the RD. Major components of the difference between the increase in non-fuel revenues approved in the order and PNM’s request, include:

A ROE of 9.575%, compared to the 10.5% requested by PNM
Inclusion of the January 2016 purchase of the assets underlying three leases of capacity, totaling 64.1 MW, of PVNGS Unit 2 (Note 6)13) at an initial rate base value of $83.7 million, compared to PNM’s request for recovery of the fair market value purchase price of $163.3 million; and disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW was being leased by PNM, which costs totaled $43.8 million when the order was issued
Disallowance of the recovery of any future contributions for PVNGS decommissioning costs related to the 64.1 MW of capacity in PVNGS Unit 2 purchased in January 2016 and the 114.6 MW of the leased capacity in PVNGS Units 1 and 2 that were extended for eight years beginning January 15, 2015 and 2016 (Note 6)13)
Disallowance of recovery of the costs associated with converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS (Note 12), but allows recovery of avoided operating and maintenance expenses of $0.3 million annually related to BDT;; PNM’s share of the costs of installing the BDT equipment was $52.3 million, $40.0 million of which PNM requested be included in rate base in the NM 2015 Rate Case
Disallowance of recovery of $4.5 million of amounts recorded as regulatory assets and deferred charges

The order continues the renewable energy rider and approved certain aspects of PNM’s proposals regarding rate design, but did not approve certain other rate design proposals or PNM’s request for a revenue decoupling pilot program. The order also proposed changes in the methods of recovering certain costs through PNM’s FPPAC and renewable energy rider. The order credits retail customers with 100% of the New Mexico jurisdictional portion of revenues from “refined coal” (a third-party pre-treatment process) at SJGS. The order approved PNM’s proposals for revised depreciation rates (with certain exceptions), the inclusion of construction work in progress in rate base, and the ratemaking treatment of the “prepaid pension asset.”

On September 30, 2016, PNM filed a notice of appeal with the NM Supreme Court regarding the order in the NM 2015 Rate Case. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which stated PNM is appealing the NMPRC’s determination that PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing BDT equipment on SJGS Units 1 and 4. Specifically, PNM’s statement indicated it is appealingappeal includes the following specific elements of the NMPRC’s order:

Disallowance of recovery of the full fair market value purchase price of the 64.1 MW of capacity in PVNGS Unit 2 purchased in January 2016
Disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity was leased by PNM
Disallowance of recovery of future contributions for PVNGS decommissioning attributable to 64.1 MW of purchased capacity and the 114.6 MW of capacity under the extended leases
Disallowance of recovery of the costs of converting SJGS Units 1 and 4 to BDT

NEE, NMIEC, and ABCWUA filed notices of cross appeal to PNM’s appeal. The issues that are being appealed by the various cross-appellants are:

The NMPRC allowing PNM to recover the costs of the lease extensions for the 114.6 MW of PVNGS Units 1 and 2 and any of the purchase price for the 64.1 MW in PVNGS Unit 2
The NMPRC allowing PNM to recover the costs incurred under the new coal supply contract for Four Corners
The revised method to collect PNM’s fuel and purchased power costs under the FPPAC
The final rate design
The NMPRC allowing PNM to include the “prepaid pension asset” in rate base

NEE subsequently filed a motion for a partial stay of the order at theThe NM Supreme Court which was denied. The NM Supreme Courthas stated that the court’s intent waswould be to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits.

On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule was completed on July 21, 2017. Oral argument at the NM Supreme Court is scheduled forwas held on October 30, 2017. Although appeals of regulatory actions of the NMPRC have a priority at the NM Supreme Court under New Mexico law, there is no required time frame for the court to act on the appeals.

PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicatesindicated it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the issues, those issues would be remanded back to the NMPRC for further action. PNM continues to estimate thatcurrently estimates it will take a minimum of 15five months from the date PNM filed its appeal,June 30, 2018 for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order will remain in effect. Accordingly, at September 30, 2016, PNM recorded a pre-tax regulatory disallowance of $11.3disallowances through June 30, 2018 aggregating $16.2 million, representing 15 months of capital cost recovery for the period October 1, 2016 through November 30, 2018 on its investments that the order disallowed, as well asand amounts recorded as regulatory assets and deferred charges

that the order disallowed, and which PNM did not challenge in its appeal. Additional losses will be recorded if the currently estimated 15 month time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is further extended.

PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurred and that PNM is entitled to full recovery of those investments through the ratemaking process. PNM believes it is reasonably possible that its appeals will be successful, but cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record additional pre-tax losses related to any unsuccessful issues. The SeptemberJune 30, 20172018 book values of PNM’s investments that the order disallowed, after considering the losslosses recorded in 2016,through June 30, 2018, were $76.9$74.4 million for the 64.1 MW of purchased capacity in PVNGS Unit 2, $39.9$38.6 million for the PVNGS Unit 2 disallowed capital improvements, and $50.0$50.5 million for the BDT equipment.

PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, if the NM Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any cost recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $153.4$148.7 million at SeptemberJune 30, 20172018 (which amount includes $76.9$74.4 million that is the subject of PNM’s appeal discussed above) after considering the losslosses recorded in 2016.through June 30, 2018. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and “prepaid pension asset” in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have a financial impact to PNM.

New Mexico 2016 Rate Case – On December 7, 2016,January 16, 2018, the NMPRC issued an order that authorized PNM filedto implement an application withincrease in base non-fuel rates of $10.3 million. PNM implemented 50% of the NMPRCapproved increase for service rendered, rather than bills sent, beginning February 1, 2018 and will implement the rest of the increase for service rendered beginning January 1, 2019. This order was on PNM’s application for a general increase in retail electric rates (the “NM 2016 Rate Case”). PNM filed in December 2016. PNM’s December 2016 application requested an increase in based non-fuel revenues of $99.2 million based on a FTY beginning January 1, 2018 and did not include a request to recover any of the costs disallowed in the NM 2015 Rate Case that are at issue in itsPNM’s pending appeal to the NM Supreme Court. Key aspectsThe primary drivers of the revenue deficiency in PNM’s request in the NM 2016 Rate Case are:application were:

An increaseImplementation of the modifications in base non-fuel revenuesPNM’s resource portfolio, which were previously approved by the NMPRC as part of $99.2 millionthe SJGS regional haze compliance plan (see below and Note 11)
Based on a FTY beginning January 1, 2018 (the NMPRC’s rules specify that a FTY is a 12 month period beginning upInfrastructure investments, including environmental upgrades at Four Corners
Declines in forecasted energy sales due to 13 months aftersuccessful energy efficiency programs and other economic factors
Updates in the filing of a rate case application)FERC/retail jurisdictional allocations
ROE of 10.125%
Drivers of revenue deficiency
◦Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (see below and Note 11)
◦Infrastructure investments, including environmental upgrades at Four Corners
◦Declines in forecasted energy sales due to successful energy efficiency programs and other economic factors
◦Updates in the FERC/retail jurisdictional allocations
Proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation
◦Increased customer and demand charges

◦A “lost contribution to fixed cost” mechanism applicable to residential and small commercial customers to address the regulatory disincentive associated with PNM’s energy efficiency programs

TheAfter NMPRC scheduled a public hearing to begin on June 5, 2017 and ordered that a settlement conference should be held. After settlement discussions were held, PNM and representatives of several intervenors reached an agreement on the parameters for a settlement in this proceeding. In May 2017, PNM and thirteen intervenors (the “Signatories”) entered into a comprehensive stipulation. On May 12, 2017, the Hearing Examiners issued an order rejecting the stipulation in its current form and allowing the SignatoriesMay 2017, which was subsequently revised to revise the stipulation. On May 23, 2017, the Signatories filed a revised stipulation that addressed theaddress issues raised by the Hearing Examiners in their order.the case. NEE iswas the sole party opposing the revised stipulation. The terms of the revised stipulation include:included:

A revenue increase totaling $62.3 million, with an initial increase of $32.3 million beginning January 1, 2018 and the remaining increase beginning January 1, 2019
A ROE of 9.575%, compared to the 10.125% requested by PNM
Full recovery of thePNM’s investment in SCRs at Four Corners with a debt-only return
An agreement to not to seek to adjustimplement non-fuel base rate changes, other than changes related to bePNM’s rate riders, with an effective date prior to January 1, 2020
An agreement to adjust the January 2019 increase for certain changes in federal corporate tax laws and to true-up PNM’s cost of debt
Returning to customers over a three-year period the benefit of the reduction in the New Mexico corporate income tax rate to the extent attributable to PNM’s retail operations
PNM will withdrawwould perform a cost benefit analysis in its proposal for2020 IRP of the impact of a “lost contribution to fixed cost” mechanism with the issue to be addressedpossible early exit from Four Corners in a future docket2024 and 2028

On May 24, 2017, the NMPRC issued an order, which resulted in the tolling of the statutory suspension period for two months and extending the suspension of the rate increase until January 6, 2018. The NMPRC can further extend the suspension period for an additional two months. A public hearing on the revised stipulation was held in August 2017. The revised stipulation requiresOn October 31, 2017, the approvalHearing Examiners issued a Certification of the NMPRC in orderStipulation recommending modifications to take effect.

If the NMPRC approves the revised stipulation that would identify PNM’s decision to continue its participation in Four Corners as filed, imprudent, not allow PNM to collect a debt or equity return on $148.1 million of investments in SCRs and other projects at Four Corners, and to temporarily disallow recovery of $36.8 of PNM’s projected capital improvements at SJGS.

Extensive proceedings before the NMPRC were conducted in December 2017 and January 2018 as described in Note 12. Ultimately, the NMPRC’s January 16, 2018 order approved the Certification of Stipulation with certain changes, which included allowing PNM to recover its $148.1 million of investments in SCR and other projects at Four Corners with a debt-only return (but maintaining the recommended disallowance of an equity return), deferring further consideration regarding the prudency of PNM’s decisions to continue its participation in Four Corners to PNM’s next general rate case, requiring the impacts of changes related to the reduction in the federal corporate income tax rate and PNM’s cost of debt (aggregating an estimated $47.6 million) be implemented in 2018 rather than January 1, 2019, and requiring PNM to reduce its requested $62.3 million increase in non-fuel revenues by $4.4 million.

GAAP would requirerequired PNM to recognize a loss reflecting that it will earn a debt-only return on $148.1 million of investments at Four Corners rather than a full return. Accordingly, PNM recorded a pre-tax regulatory disallowance of $27.9 million as of December 31, 2017.

On February 7, 2018, NEE filed a notice of appeal with the NM Supreme Court asking the court to reflectreview the NMPRC’s decisions in the NM 2016 Rate Case. On March 7, 2018, NEE filed its statement of issues with the NM Supreme Court requesting, among other things, that the NMPRC be required to identify PNM’s decision to continue its participation in Four Corners as imprudent and to deny any recovery related to PNM’s $148.1 million of investments in Four Corners. NEE’s Brief in Chief was filed on July 16, 2018 and PNM’s Answer Brief is due on September 12, 2018. Several parties to the case are participating in the appeal as intervenor-appellees in support of the NMPRC’s final decisions in the case. Although PNM does not believe it is probable that NEE’s appeal will be successful, it is unable to predict what decision the NM Supreme Court will reach. If the NM Supreme Court were to remand the case to the NMPRC and the NMPRC identified PNM’s continued involvement in Four Corners as imprudent with no recovery of the $148.1 million of investments in Four Corners, PNM would not earn an equity return on itsbe required to record additional losses for the remaining amount of those investments (after considering the $27.9 million regulatory disallowance recorded in 2017). In addition, PNM’s future investments in SCRs at Four Corners. The loss wouldCorners, which could be recorded as a regulatory disallowance as ofrequired under the date of NMPRC approval. Such amount would depend on the final costs of the SCRs and other factors and assumptions at the date of NMPRC approval. Based on the revised stipulation and PNM’s current assumptions, PNM estimates the regulatory disallowance wouldparticipation agreement governing that facility, could also be approximately $21 million.subject to disallowance. PNM cannot predict the outcome of this matter.
TNMP 2018 Rate Case – On May 30, 2018, TNMP filed a general rate proceeding with the PUCT (the “TNMP 2018 Rate Case”), which requests an annual increase to base rates of $25.9 million based on a requested ROE of 10.5% and a capital structure comprised of 50% debt and 50% equity. TNMP’s request includes $7.7 million of new rate riders to recover Hurricane Harvey restoration and additional vegetation management costs. The application includes the integration of revenues currently recorded under the AMS rider and collection of other unrecovered AMS investments into base rates. In 2017, TNMP recorded revenues of $21.8 million under the AMS rider. The TNMP 2018 Rate Case application also proposes to return the regulatory liability recorded at December 31, 2017 related to tax reform to customers and to reduce its federal corporate income tax rate to 21%. If approved by the PUCT, new rates are expected to become effective in early 2019. A hearing is currently scheduled to begin September 7, 2018. TNMP cannot predict the outcome of this matter.

San Juan Generating Station Unit 1 Outage – On March 17, 2018, a coal silo used to supply fuel to SJGS Unit 1 collapsed resulting in an outage. PNM initiated a review of the cause of the outage and promptly contacted the staff of the NMPRC to inform them of the event. To minimize the operational and financial impacts of this event, PNM accelerated the fall 2018 planned outage on Unit 1 to be performed while the unit was out of service for this event. Repairs necessary to return Unit 1 to service were completed by July 5, 2018. PNM anticipates the damages to the facility related to the coal silo collapse are reimbursable under an existing property insurance policy that covers SJGS, subject to a deductible of $2.0 million.  PNM’s exposure to the cost of repairs is $1.0 million, reflecting PNM’s 50% ownership interest in SJGS Unit 1.
On April 12, 2018, NEE filed a petition (jointly with certain other organizations) requesting that the NMPRC order an investigation into the SJGS Unit 1 event.  The petition requested that the NMPRC order PNM to respond to the petition, that proceedings be set on this matter, and that PNM be required to provide a narrative explanation, cost/benefit analysis, and alternatives assessment used to determine that Unit 1 should be repaired rather than utilizing alternative resources.  Pursuant to an NMPRC order, PNM filed a response on May 8, 2018 indicating that it used best practices when inspecting the SJGS coal silos during planned outages, that the damage to SJGS Unit 1 was repairable and could be made in a timely manner, that all but a limited amount of cost of the repairs are reimbursable under an existing insurance policy, and that further proceedings on the matter were unnecessary. In addition, PNM’s response indicated that if the unit were not repaired, customers would be exposed to significant contractual liabilities under the agreements governing the ownership of SJGS and would incur significant additional costs associated with the procurement of replacement power. On May 31, 2018, the NMPRC staff preliminarily recommended that the NMPRC not allow PNM to recover any costs associated with the SJGS Unit 1 coal silo repairs, including the cost of preventing similar

failures on other SJGS coal silos, and that PNM reimburse customers for the loss of off-system sales during the time SJGS Unit 1 was in outage. The NMPRC staff also recommended, among other things, that further proceedings on the matter be deemed unnecessary provided PNM agree to hold customers harmless for such costs. On June 15, 2018, PNM filed a motion requesting the NMPRC extend the deadline for PNM’s response to staff’s preliminary recommendation until August 17, 2018. The NMPRC has not yet acted on this motion. PNM cannot predict the outcome of this matter.

Advanced Metering – In September 2011, TNMP began its deployment of advanced meters for homes and businesses across its service area. TNMP completed its mass deployment in 2016 and has installed more than 242,000 advanced meters. 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, TNMP recently completed installation of a new outage management system that will leverage capabilities of the advanced metering infrastructure to enhance TNMP’s responsiveness to outages.

On February 26, 2016, PNM filed an application with the NMPRC requesting approval of a project to replace its existing customer metering equipment with Advanced Metering Infrastructure (“AMI”). The application also asksasked the NMPRC to authorize the recovery, in future ratemaking proceedings, of the cost of the project, currently estimated to be $95.1 million, as well as to approve the recovery of the remaining undepreciated investment in existing metering equipment, estimated to be approximately $33 million and the costs of customer education, and severance for any affected employees. Hearings on the AMI application concluded inOn March 2017. During the March 2017 hearing, it was disclosed that the proposed meter contractor may not have complied with certain New Mexico contractor licensing requirements. PNM subsequently filed testimony regarding that matter as ordered by19, 2018, the Hearing Examiner issued a recommended decision finding that PNM had not proven a net public benefit in the case and requestedrecommending the NMPRC not approve the application. On April 2, 2018, PNM filed a new procedural schedule to allow it to issue a new RFP for contracting work relatedstatement on exceptions to the meter installation and to update its cost-benefit analysis. An additional hearing was held on October 25-26, 2017.recommended decision indicating, among other things, that PNM does not intend to proceeddisagreed with the AMI project unlessfinding that the record did not demonstrate a net public benefit to customers, but that PNM would not take exception to a recommendation to not approve the application. On April 11, 2018, the NMPRC approvesadopted an order accepting the entirerecommended decision and disapproving PNM’s application. PNM cannot predict the outcome of this matter.

PVNGS Unit 3 –Currently,The order indicated PNM’s 134 MW interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates. The power generated from that interest is sold into the wholesale market and any earnings or losses are realized by shareholders. As part of compliance with the requirementsnext energy efficiency plan filing should include a proposal for BART at SJGS discussed below, the NMPRC approved including PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018. PVNGS Unit 3 is

included as a jurisdictional resource in PNM’s NM 2016 Rate Case.an AMI pilot project.

Rate Riders and Interim Rate Relief – 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. This permits more timely recovery of investments. The PUCT has also approved riders that allow TNMP to recover amounts related to AMS, energy efficiency, third-party transmission costs, and the CTC. The NMPRC has approved PNM recovering fuel costs through the FPPAC, as well as rate riders for renewable energy and energy efficiency that allow for more timely recovery of investments and improve PNM’s ability to earn its authorized return.

TNMP General Rate Case – TNMP’s last general rate case was filed in 2010 with new rates becoming effective on February 1, 2011. In connection with TNMP’s deployment of its AMS, TNMP has committed to file a general rate case no later than September 1, 2018. TNMP currently anticipates filing its general rate case in May 2018 using a 2017 calendar year test period.  New rates are anticipated to become effective during January 2019. 

FERC Regulation

Rates PNM charges forwholesale transmission customers and wholesale generation services customers are subject to traditional rate regulation by FERC. ForRates charged to wholesale electric transmission customers are based on a numberformula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The formula includes updating cost of years, PNM allocatedservice components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected transmission capital projects to be placed into service in the following year. The projections included are subject to true-up. Certain items, including changes to return on equity and depreciation rates, require a portion of its generation assetsseparate filing to servebe made with FERC wholesale generation services customers. before being included in the formula rate.

The low natural gas price environment has resulted in market prices for power being substantially lower than what PNM is able to offer wholesale generation 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 generation contracts. Consequently, PNM decided to stop pursuing wholesale generation contracts. Currently, PNMcontracts and currently has no full-requirements wholesale generation customers.

Navopache Electric Cooperative, Inc. –PNM had a PSA, which contained an expiration date in 2035, to supply power to NEC that 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 could 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.

On October 29, 2015, PNM and NEC entered into, and filed with FERC, a settlement agreement, which FERC approved in January 2016. Under the agreement, PNM served all of NEC’s load through December 31, 2015 at rates that were substantially consistent with those provided under the PSA. In 2016, PNM served all of NEC’s load at reduced demand and energy rates from those under the PSA. The PSA terminated on December 31, 2016. In 2017, PNM is serving 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 available under short-term market rates at the time of the settlement. For the nine months ended September 30, 2017 and 2016, amounts billed to NEC were $3.3 million and $14.8 million. Although the settlement agreement will negatively impact results of operations in 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’s NM 2016 Rate Case discussed above proposes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve NEC.
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 of their investment in the Company’s business. PNMR’s current target is 7% to 8%6% earnings and dividend growth for the period 20152018 through 2019.2021. Earnings growth is based on ongoing earnings, which is a non-GAAP financial measure that excludes from GAAP earnings certain non-recurring, infrequent, and other items that are not indicative of fundamental changes in the earnings capacity of the Company’s operations. PNMR uses ongoing earnings to evaluate the operations of the Company and to establish goals, including those used for certain aspects of incentive compensation, for management and employees.
PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. PNMR expects to provide above industry-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. The Board approved the following increases in the indicated annual common stock dividend:

Approval Date Percent Increase
February 2012 16%
February 2013 14%
December 2013 12%
December 2014 8%
December 2015 10%
December 2016 10%
December 20179%

Maintaining Solid Investment Grade Credit Ratings
The Company is committed to maintaining solid investment grade credit ratings in order to reduce the cost of debt financing and to help ensure access to credit markets, when required. 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. In January 2018, S&P haschanged the outlook for PNMR, PNM, and TNMP on afrom stable outlook.to negative. In June 2017,2018, Moody’s changed the outlook for PNMR and PNM from positive to stable to positive while maintaining aand maintained the stable outlook for TNMP.

Business and Strategic Focus

PNMR strives to create enduring value for customers, communities, and shareholders. PNMR’s strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power. The Company 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. Equally important is the focus of PNMR’s utilities on customer satisfaction and community engagement.

Reliable and Affordable Power
PNMR and its utilities are aware of the important roles they play in enhancing economic vitality in their service territories. Management believes that maintaining strong and modern electric infrastructure is critical to ensuring reliability and supporting economic growth. When contemplating expanding or relocating their operations, 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. 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.

Utility Plant and Strategic Investments

Utility Plant Investments – During the 20142015 to 20162017 period, PNM and TNMP together invested $1,541.4$1,552.0 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. PNM completed the 40 MW natural gas-fired La Luz peaking generating station located near Belen, New Mexico in December 2015. PNM also completed installation of SNCR and BDT equipment on SJGS Units 1 and 4 in early 2016 and the addition of 40 MW of PNM-owned solar PV facilities in 2015. In addition, on January 15, 2016, PNM completed the $163.3 million acquisition of 64.1 MW of capacity in PVNGS Unit 2 that had previously been leased to PNM. During 2018 and 2019, PNM will construct an additional 50 MW of PNM-owned PV facilities, which were approved by the NMPRC in PNM’s 2018 renewable energy procurement plan. The 50 MW PV facilities are expected to be completed in stages throughout 2019 at a cost not to exceed $73.0 million.

Strategic Investments – In 2017, PNMR Development and AEP OnSite Partners created NM Renewable Development, LLC (“NMRD”) to pursue the acquisition, development, and ownership of renewable energy generation projects, primarily in the state of New Mexico. Abundant renewable resources, large tracts of affordable land, and strong government and community support make New Mexico a favorable location for renewable generation. New Mexico has the 2nd highest technical potential of the 48 contiguous states for utility scale solar photovoltaics as noted in 2015 by the National Renewable Energy Laboratory, while New Mexico is 6th for technical potential for land-based wind. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. Through NMRD, PNMR anticipates being able to provide additional renewable generation solutions

to customers within and surrounding its regulated jurisdictions through partnering with a subsidiary of one of the United States’ largest electric utilities. The formation of this joint venture provides a more efficient use of PNMR’s capital to support new renewable investment opportunities while maintaining the necessary capital to support investments required by regulated jurisdictions. NMRD’s current renewable energy capacity in operation is 31.8 MW, which includes 30 MW of solar-PV facilities required to supply energy to the new Facebook data center located within PNM’s service territory and 1.8 MW to supply energy to Columbus Electric Cooperative located in southwest New Mexico. NMRD actively explores opportunities for additional renewable projects, including large-scale projects to serve future data centers and other customer needs.

Integrated Resource Plan

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

PNM filed its 2017 IRP on July 3, 2017. Under the NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 11, PNM is required to make a filing in 2018 to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after June 30, 2022. The 2017 IRP analyzed several scenarios utilizing as

sumptionsassumptions that PNM continues service from its SJGS capacity beyond mid-2022 and that PNM retires its capacity after mid-2022. Key findings of the 2017 IRP include:

Retiring PNM’s share of SJGS in 2022 after the expiration of the current operating and coal supply agreements would provide long-term cost savings for PNM’s customers
PNM exiting its ownership interest in Four Corners after its current coal supply agreement expires in 2031 would also provide long-term cost savings for customers
The best mix of new resources to replace the retired coal generation would include solar energy and flexible natural gas-fired peaking capacity; the mix could include energy storage if the economics support it and wind energy provided additional transmission capacity becomes available
Significant increases in future wind energy supplies will likely require new transmission capacity to be built from eastern New Mexico to PNM’s service territory
PNM should retain the currently leased capacity in PVNGS, which would avoid replacement with carbon-emitting generation
PNM should continue to develop and implement energy efficiency and demand management programs
PNM should assess the costs and benefits of participating in the California Energy Imbalance Market
PNM should analyze its current Reeves Generating Station to consider possible technology improvements to phase out the older generators and replace them with new, more flexible supplies or energy storage

Several parties have filed protests to the 2017 IRP. The issues addressed in the protestprotests include PNM’s future interest in SJGS, Four Corners, and PVNGS and the timing of future procurement of renewable resources. The 2017 IRP is not a final determination of PNM’s future generation portfolio. Retiring PNM’s share of SJGS capacity and exiting Four Corners would require NMPRC approval of abandonment filings, which PNM would make at appropriate times in the future. Likewise, NMPRC approval of new generation resources through CCN filings would be required. Hearings began on June 4, 2018 and concluded on June 12, 2018. PNM cannot predict the ultimate outcome of the 2017 IRP process or whether the NMPRC will approve subsequent filings that would encompass actions to implement the conclusions of the 2017 IRP.
Environmentally Responsible Power
PNMR has a long-standing record of environmental stewardship. PNM’s environmental focus has beenis in three key areas:

•
Developing strategies to meet regional haze rules at the coal-fired SJGS as cost-effectively as possibleprovide reliable and affordable power, while providing broad environmental benefits that also demonstrate progress in addressingtransforming PNM’s generation resources to a cleaner energy portfolio by reducing CO2 emissions from existing power plants
Preparing PNM’s system to meet New Mexico’s increasing renewable energy requirementsresources as cost-effectively as possible
Increasing energy efficiency participation

PNMR’s Sustainability Portal provides key environmental and sustainability information related to PNM’s and TNMP’s operations and is available at http://www.pnmresources.com/about-us/sustainability-portal.aspx. The portal also contains a Climate

Change Report, which outlines plans to be coal-free by 2031 (subject to regulatory approval). This could enable an 87% reduction in CO2 emissions in 2040 compared to 2012 levels, which is a significantly greater reduction than that required of New Mexico under EPA’s Clean Power Plan. As discussed below, PNM shutdown SJGS Units 2 and 3 in December 2017, which is expected to result in a 40% reduction in CO2 emissions in 2018 compared to 2012 levels.

SJGS

Regional Haze Rule Compliance Plan – In December 2015, PNM received NMPRC approval for the plan to comply with the EPA regional haze rule at SJGS that minimizes the cost impact to customers while still achieving broad environmental benefits. Under the approved plan, the installation of SNCRs on SJGS Units 1 and 4 was completed in early 2016 and Units 2 and 3 will bewere retired by the end ofin December 2017. The plan provides for similar visibility improvements, but at a lower cost to PNM customers than a previous EPA ruling that would have required the installation of more expensive SCRs on all four units at SJGS. The plan has the added advantage of reducing other emissions in addition to NOx, including SO2, particulate matter, CO2, and mercury, as well as significantly reducing water usage. Additional information is contained in Note 16 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K and in Note 11.

Under the key provisions of theThe December 2015 order approving the compliance plan, PNM:also provided, among other things, that:

Will retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) by December 31, 2017 and recover, over 20 years, 50% (currently estimated to be approximately $128.6 million) of their undepreciated net book value at that date and earn a regulated return on those costs
IsPNM was granted a CCN to acquire an additional 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 (see New Mexico Rate Cases above and Note 12)effective January 1, 2018
IsPNM was granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equalas a jurisdictional resource to the book value as of December 31, 2017 (currently estimated to be approximately $155 million)serve New Mexico customers beginning January 1, 2018

IsPNM was authorized to acquire 65 MW of SJGS Unit 4 as merchant utility plant which
No later than December 31, 2018, and before entering into a binding coal supply agreement for SJGS, PNM will not be included in rates charged to retail customers
Will accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022
Is required to make a NMPRC filing in 2018 to determine the extent that SJGS should continue serving PNM’s customers’ needs after mid-2022
•
Will acquire and retire one MWh of RECs that include a zero-CO2 emission attribute beginning January 1, 2020 for every MWh produced by 197 MW of coal-fired generation from PNM’s ownership share of SJGS (the cost of these RECs would be capped at $7.0 million per year and recovered in rates)
Will not recover approximately $20 million of increased operations and maintenance expenses and other costs incurred in connection with CAA compliance

At December 31, 2015, PNM recorded pre-tax losses aggregating $165.7 million to reflect the write-off of the 50% of the estimated December 31, 2017 net book value of SJGS Units 2 and 3 that will not be recovered, the other unrecoverable costs, and the increase in the estimated liability recorded for coal mine reclamation resulting from the new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”). In 2016, PNM recorded additional pre-tax losses of $3.7 million resulting from revised estimates of these items. Additional information about the CSA is discussed below and in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 11.

On January 14, 2016, NEE filed a Noticenotice of Appealappeal with the NM Supreme Court of the NMPRC’s December 2015 order. TheOn March 5, 2018, the NM Supreme Court has taken no action onissued its opinion affirming the appeal and thereNMPRC’s December 2015 order, thereby denying NEE’s appeal. This matter is no required time frame for the court to act on the appeals. On March 31, 2016, NEE filed a complaint against PNM with the NMPRC regarding the financing provided by NM Capital to facilitate the sale of SJCC. The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. The NMPRC has taken no action on this matter.now concluded.

SJGS Ownership Restructuring and Other Matters – In connection with the proposed retirement ofplan to comply with EPA regional haze rules at 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 negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items.

The San Juan Project Restructuring Agreement (“SJGS RA”) sets forth the agreement among the SJGS owners regarding ownership restructuring. Key provisions of the RA include:

Capacity acquisition – On December 31, 2017, PNM will acquire 132 MW of the exiting owners’ capacity in SJGS Unit 4restructuring and PNMR Development agreed to acquire 65 MW of such capacity. PNMR Development has assigned the rights and obligationsaddresses other related to the 65 MW to PNM effective on December 31, 2017, which will facilitate dispatch of power frommatters, including that capacity. As ordered by the NMPRC, PNM will treat the 65 MW as merchant utility plant that will be excluded from retail rates. In anticipation of the transfer of ownership, PNM entered into agreements to sell the power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022.
Coal inventory – The RA also sets forth the terms under which PNM acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and is providing coal supply to the exiting participants during the period from January 1, 2016 through December 31, 2017, which arrangement provides economic benefitsremain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are being passed onattributable to PNM’s customers through the FPPAC.
Coal supply –activities that occurred prior to their exit. The SJGS RA became effective contemporaneously with the effectiveness of the new SJGS CSA for SJGS. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which occurred on January 31, 2016. In supportSee Note 11.

Although the SJGS RA results in an agreement among the SJGS participants enabling compliance with current CAA requirements, it is possible that the financial impact of climate change regulation or legislation, 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. PNM’s 2017 IRP (Note 12), presented resource portfolio plans for scenarios that assumed SJGS will operate beyond the end of the closingcurrent coal supply agreement that runs through June 30, 2022 (Note 11) and for scenarios that assumed SJGS will cease operations after mid-2022. The 2017 IRP data shows that retiring SJGS in 2022 would provide long-term cost benefits to PNM’s customers.

The 2017 IRP is not a final determination of PNM’s future generation portfolio.  Retiring PNM’s share of SJGS would require PNM to make a formal abandonment filing with the NMPRC.  The final determination of PNM’s exit from SJGS would be subject to NMPRC review and approval.  PNM would also be required to obtain NMPRC approval of replacement power resources through formal CCN filings. The December 2015 NMPRC order discussed above authorized PNM to acquire 132 MW of SJGS Unit 4 as a New Mexico jurisdictional resource and 65 MW of SJGS Unit 4 as merchant plant. That order also provides that, if SJGS Unit 4 is abandoned with undepreciated investment on PNM’s books, PNM would not be allowed to recover the undepreciated investment of its 132 MW interest. PNM is currently depreciating all its investments in SJGS through 2053, the expected life approved by the NMPRC.  PNM’s undepreciated investment in SJGS at June 30, 2018 was $406.4 million, which includes interests in the 132 MW and the 65 MW of $20.5 million and $10.2 million.  In the event of an early retirement of SJGS,

PNM would be exposed to loss of its undepreciated investments in the facility and other costs, including costs associated with coal mine reclamation, if recovery of these items is not approved by the NMPRC. The financial impact of early retirement and the NMPRC approval process are influenced by factors outside of PNM’s control, including the economic impact of a potential SJGS abandonment on the area surrounding the plant and related mine, as well as overall political and economic conditions in New Mexico. Because of the mine purchaseuncertainty in obtaining the required approvals, PNM is unable to predict the outcome of this matter.

As discussed in Note 11, PNM has the option to extend the SJGS CSA, which currently expires on June 30, 2022, subject to negotiation of the term of the extension and to facilitate PNM customer savings, NM Capital, a wholly-owned subsidiary of PNMR, provided funding of $125.0 million to Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price. NM Capital was able to provide the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement with a commercial bank. PNMR guarantees NM Capital’s obligationscompensation to the bank. The Westmoreland Loan matures on Februaryminer. In order to extend, the SJGS CSA provides that PNM must give written notice of that intent by July 1, 20212018 and had an initial interest rate of 7.25% plus LIBOR, which escalates over time. Such rate is 9.25% plus LIBOR for the period from February 1, 2017 through January 31, 2018. WSJparties must pay principal and interest quarterlyagree to NM Capital in accordance with an amortization schedule. As of October 20, 2017, the balance of the Westmoreland Loan was $66.2 million. The next principal payment

of $9.6 million plus interest of $1.8 million is due on November 1, 2017. As of October 20, 2017, $11.4 million was held in a SJCC restricted bank account that is to be used solely to service the Westmoreland Loan.
Coal mine reclamation – Under the terms of the extension by January 1, 2019. In addition, the SJPPA obligates each SJGS participant to provide notice to the other participants whether they wish to extend the SJPPA and SJGS CSA beyond June 30, 2022. Los Alamos, UAMPS, and Tucson provided notice of their intent to exit SJGS in 2022. Farmington gave notice that it wishes to continue SJGS operations and to extend the terms of both agreements. PNM gave preliminary notice to the other participants that, based on updated coal pricing and other relevant information, PNM does not wish to extend the terms of the agreements beyond June 30, 2022. PNM is continuing to analyze the permanent retirement of SJGS in 2022 and the final determination of PNM’s exit from SJGS is subject to NMPRC approval in a formal abandonment proceeding (Note 12). Due to Farmington’s stated interest in continuing SJGS operations beyond 2022, PNM and Westmoreland agreed to extend the other SJGS owners are obligatedJuly 1, 2018 notice deadline to compensate SJCC for all reclamation costs associated with the supply of coal from the San Juan mine. In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds, which currently aggregate $118.7 million, with the NMMMD. PNMR has arrangements under which a bank has issued $30.3 million in letters of credit to facilitate posting of the required reclamation bonds. See Note 11.December 1, 2018.
Other SJGS Environmental Matters – 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 rules regarding GHG under Section 111(d) of the CAA. Implementation of the Clean Power Plan, which was published by EPA in October 2015, is currently stayed by order of the US Supreme Court pending further proceedings before the DC Circuit. Oral argument was heard by the DC Circuit in September 2016, but the court has taken no action. On March 28, 2017, President Trump issued an Executive Order on Energy Independence.  The order sets out two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is affordable, reliable, safe, secure, and clean.  The order rescinds various actions undertaken by the previous administration and directs the EPA Administrator to review and if appropriate suspend, revise, or rescind the Clean Power Plan, as well as other environmental regulations. On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan. The proposal would change thePlan based on a legal interpretation to conclude thatof the CAA under which the Clean Power Plan exceeds EPA’s statutory authority. A 60-day public comment period will follow publication ofEPA published the proposed repeal rule inon October 16, 2017 and accepted public comments through April 26, 2018. In addition, EPA published an advance NOPR on December 28, 2017 to take comment on whether EPA should adopt a rule to replace the Federal RegisterClean Power Plan and any final rule will be subject to legal challenge and judicial review. EPA also noted that it is still evaluating whether to adoptwhat such a replacement rule to regulate GHG from existing electric utility generating units.
might include, for which public comments were due February 26, 2018. PNM estimates that implementation of the BART plan at SJGS, as well asalong with potentially exiting ownership in the remaining units at SJGS and(as well as Four Corners, which areCorners), as discussed above, should provide significant steps for New Mexico to meet its ultimate compliance with Section 111(d). under the Clean Power Plan or any replacement rule. PNM is unable to predict the impact of this rule on its fossil-fueled generation.generation portfolio.
Because of environmental upgrades completed in 2009, SJGS ishas a mercury removal efficiency of 98% and mercury emissions are well positioned to outperformbelow the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. Major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO2, particulate matter, and mercury. SinceBetween 2006 and 2017, SJGS has reduced emissions of NOx emissions by 46%41%, SO2 by 78%70%, particulate matter by 75%61%, and mercury by 98%.
Renewable Energy
PNM’s renewable procurement strategy includes utility-owned solar capacity, as well as wind and geothermal energy purchased under PPAs. As of December 31, 2017, PNM had 107 MW of utility-owned solar capacity. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 91.9 MW at June 30, 2018. 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 was one of the first combinations of battery storage and PV energy in the nation and involved extensive research and development of advanced grid concepts. The facility also was the nation’s first solar storage facility fully integrated into a utility’s power grid. Since 2003, PNM has purchased the output from New Mexico Wind, a 204 MW wind facility, and began purchasing the output of Red Mesa Wind, an existing 102 MW wind energy center, on January 1, 2015. PNM has a 20-year agreement to purchase energy from the Lightning Dock Geothermal facility built near Lordsburg, New Mexico. The geothermal facility, which has a current capacity of 4 MW, began providing power to PNM in January 2014. PNM also purchases RECs as necessary to meet the RPS.
The majority of these renewable resources are key means for PNM to meet the RPS and related regulations that 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 2017 renewable energy procurement plan meets RPS and diversity requirements for 2017 and 2018 using existing resources and does not propose any significant new procurements. PNM’s 2018 renewable energy procurement plan requested approval to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; approval to procure an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; approval to procure 50 MW of new solar facilities to be constructed beginning in 2018; continuation of customer REC purchase programs; and other purchases of RECs to ensure annual compliance with the RPS. On November 15, 2017, the NMPRC issued an order approving PNM’s plan. NMIEC filed an appeal with the NM Supreme Court objecting to the fuel allocation methodology. NEE filed a motion to intervene and cross-appeal objecting to the approval of the 50 MW of new solar facilities. PNM and other parties have granted approval to intervene in the case. On February 27, 2018, the court issued an order denying a motion by NMIEC for a partial stay. On June 1, 2018, PNM filed its 2019 renewable energy procurement plan which meets RPS and diversity requirements for 2019 and 2020 using resources already approved by the NMPRC and does not propose any significant new procurements. Hearings on PNM’s 2019 renewable energy procurement plan are scheduled to begin on September 27, 2018. See Note 12. PNM cannot predict the outcome of these matters.

PNM is currently purchasing the output of 30 MW of solar capacity from NMRD that is used to serve the Facebook data center. See Strategic Investments above. In late 2017, PNM entered into three separate 25-year PPAs to purchase renewable energy and RECs to be used by PNM to supply additional renewable power to the Facebook data center. These PPAs include the purchase of the power and RECs from a 50 MW wind project to be operational at December 31, 2018, a 166 MW wind project to be operational in November 2020, and a 50 MW solar project to be operational in December 2021. The NMPRC approved these PPAs on March 21, 2018 (Note 12).
PNM will continue to procure renewable resources while balancing the impact to customers’ electricity costs in order to meet New Mexico’s escalating RPS requirements.
Energy Efficiency
Energy efficiency also plays a significant role in helping to keep customers’ electricity costs low while meeting their energy needs. PNM’s and TNMP’s energy efficiency and load management portfolios continue to achieve robust results. In 2017, incremental energy saved as a result of new participation in PNM’s portfolio of energy efficiency programs was approximately 74 GWh. This is equivalent to the annual consumption of approximately 11,000 homes in PNM’s service territory. PNM’s load management and annual energy efficiency programs also help lower peak demand requirements. In 2017, TNMP’s incremental energy saved as a result of new participation in TNMP’s energy efficiency programs was approximately 21 GWh. This is equivalent to the annual consumption of approximately 2,300 homes in TNMP’s service territory. In April 2016 and again in April 2017, TNMP was recognized by Energy Star for TNMP’s successful energy efficiency efforts. In April 2018, TNMP received the “Partner of the Year Energy Efficiency Delivery Award” for its High-Performance Homes Program.
Water Conservation and Solid Waste Reduction
PNM continues its efforts to reduce the amount of fresh water used to make electricity (about 20% more efficient than in 2007). Continued growth in PNM’s fleet of solar and wind energy sources, energy efficiency programs, and innovative uses of gray water and air-cooling technology have contributed to this reduction. Water usage will continue to decline as PNM substitutes less fresh-water-intensive generation resources to replace SJGS Units 2 and 3 starting in 2018, whenas water consumption at that plant will behas been reduced by aroundapproximately 50%. Focusing on responsible stewardship of New Mexico’s scarce water resources improves PNM’s water-resilience in the face of persistent drought and ever-increasing demands for water to spur the growth of New Mexico’s economy. 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. In 2016, 192017, 18 of the Company’s 23 facilities met the solid waste diversion goal of a 60% diversion rate, while recycling at least the same number of waste streams as 2015.2016. The Company expects to continue to do well in this area 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 December 31, 2016, PNM had 107 MW of utility-owned solar capacity. As discussed in Note 12, PNMR Development will construct and own 30 MW of new solar capacity that PNM will use to supply power to a new data center being constructed in PNM’s service territory by Facebook Inc. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 81.6 MW at September 30, 2017. 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 was one of the first combinations of battery storage and PV energy in the nation and involved extensive research and development of advanced grid concepts. The facility also was the nation’s first solar storage facility fully integrated into a utility’s power grid. Since 2003, PNM has purchased the output from New Mexico Wind, a 204 MW wind facility, and began purchasing the output of Red Mesa Wind, an existing 102 MW wind energy center, on January 1, 2015. PNM has a 20-year agreement to purchase energy from the Lightning Dock Geothermal facility built near Lordsburg, New Mexico. The geothermal facility, which has a current capacity of 4 MW, began providing power to PN

M in January 2014. PNM also purchases RECs as necessary to meet the RPS.
The majority of these renewable resources are key means for PNM to meet the RPS and related regulations that 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 2017 renewable energy procurement plan meets RPS and diversity requirements for 2017 and 2018 using existing resources and does not propose any significant new procurements. The NMPRC approved the plan on November 23, 2016. On June 1, 2017, PNM filed its 2018 renewable energy procurement plan. PNM is requesting approval to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; approval to procure an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; approval to procure 50 MW of new solar facilities to be constructed beginning in 2018; continuation of customer REC purchase programs; and other purchases of RECs to ensure annual compliance with the RPS. A hearing on the plan was held in September 2017. On October 17, 2017, the Hearing Examiner issued a recommended decision that PNM’s 2018 renewable energy procurement plan be approved by the NMPRC, except for the re-powering of Lightning Dock Geothermal and PNM’s request to procure 50 MW of new solar facilities. The Hearing Examiner recommended that the PPA for the output of energy from Lightning Dock Geothermal be terminated effective January 1, 2018. The Hearing Examiner also recommended that the 50 MW solar projects not be approved and that PNM be required to issue another all-renewables RFP within 10 days of the issuance of a final order allowing developers to utilize PNM-owned sites to construct facilities, the output from which facilities would be sold to PNM through PPAs. PNM strongly disagrees with the Hearing Examiner’s recommendations and believes they are unlawful and against the weight of evidence. Exceptions to the recommended decision are due on October 27, 2017. PNM will file its exceptions timely and will vigorously contest the Hearing Examiner’s proposals regarding Lightning Dock Geothermal and the requirement that PNM allow developers to construct renewable facilities on PNM-owned sites. PNM cannot predict the outcome of this matter.
PNM will continue to procure renewable resources while balancing the impact to customers’ electricity costs in order to meet New Mexico’s escalating RPS requirements.
Energy Efficiency
Energy efficiency also plays a significant role in helping to keep customers’ electricity costs low while meeting their energy needs. PNM’s and TNMP’s energy efficiency and load management portfolios continue to achieve robust results. In 2016, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 82 GWh. This is equivalent to the annual consumption of approximately 11,000 homes in PNM’s service territory. PNM’s load management and annual energy efficiency programs also help lower peak demand requirements. TNMP’s energy efficiency programs in 2016 resulted in energy savings totaling an estimated 22 GWh. This is equivalent to the annual consumption of approximately 2,250 homes in TNMP’s service territory. In April 2016 and again in April 2017, TNMP was recognized by Energy Star for TNMP’s successful energy efficiency efforts. TNMP received the “Partner of the Year Energy Efficiency Delivery Award” for its High-Performance Homes Program.

Customer, Stakeholder, and Community Engagement

The Company strives to deliver a superior customer experience. Through outreach, collaboration, and various community-oriented programs, the Company has a demonstrated commitment to build productive relationships with stakeholders, including customers, community partners, regulators, intervenors, legislators, and shareholders. Beginning in 2013, PNM refocusedcontinues to focus its efforts to improveenhance the customer experience through customer service improvements, including billing and payment options, strategic customer engagement, and improved communications. These efforts are supported by market research to understand the varying needs of

customers, identifying and establishing valued services and programs, and proactively communicating and engaging with customers at regional and community levels. PNM’s focus on the customer experience has resulted in increasing scores in the JD Power Electric Utility Residential Customer Satisfaction Study.customers.
The Company has leveraged a number of communications channels and strategic content to better serve and engage its many stakeholders. PNM’s website, www.pnm.com, provides the details of major regulatory filings, including general rate requests, as well as the background on PNM’s efforts to maintain reliability, keep prices affordable, and protect the environment. PNM has also leveraged social media in communications with customers on various topics such as education, outage alerts, safety, customer service, and PNM’s community partnerships in philanthropic projects. In May 2017, a chat function was added to PNM’s website to allow customers options when communicating with customer service representatives and an online management system was launched to expedite applications for solar interconnections. The website is designedcontinues 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. In September 2016, PNMR launched a dedicated sustainability portal on its corporate website www.pnmresources.com to provide additional information regarding the Company’s environmental and other sustainability efforts. The site provides the key corporate governance and sustainability information related to the operations of PNM and TNMP. In January 2018, PNM added a Climate Change Report to this portal. The information is presented under four main headings: Environment, Social, Economic, and Governance.

With reliability being the primary role of a transmission and distribution service provider in Texas'Texas’ deregulated market, TNMP continues to focus on keeping end-users updated about interruptions and to encourage customerconsumer preparation when severe weather is forecasted. In August 2017, Hurricane Harvey made landfall in the gulf coast region and TNMP employees worked diligently to restore power safely and efficiently for affected customers. In addition, PNMR made donations to support relief and restoration efforts in the gulf coast region. TNMP employees who were impacted by Hurricane Harvey were provided emergency crisis funds supported by the PNM Resources Foundation and other employee donations.
Local relationships and one-on-one communications remain two of the most valuable ways both PNM and TNMP connect with their stakeholders. Both companies maintain long-standing relationships with governmental representatives and key customerselectricity consumers to ensure that these stakeholders are updated on company investments and initiatives. Key stakeholderselectricity consumers also have dedicated Company contacts that support their important service needs.

PNMR has a long tradition of supporting the communities it serves in New Mexico and Texas. ThroughThe Company demonstrates its core value of caring through the PNM Resources Foundation, corporate giving, and widespread employee volunteerism, as well asand PNM’s low income program, the Company demonstrates its core value of caring.low-income assistance programs. In addition to the extensive engagement both PNM and TNMP have with nonprofitsnonprofit organizations in their communities, the PNM Resources Foundation provides more than $1 million in grant funding each year across New Mexico and Texas. These grants help nonprofits collaborate more efficiently, become more energy efficient,innovate or sustain programs to grow and supportdevelop business, help create community projects such as providing software coding campsspaces for NM youthspublic use, and funding murals in neighborhoods, as well as providingprovide educational opportunities supporting economic development. PNMR also provides employee matching and volunteer grants. Almost 10% of the employee matching grants provided in 2017 have been used to support hurricane relief efforts. In addition, an “employee crisis fund” funded by the PNM Resources Foundation is currently being utilized by employees in the Texas Gulf Coast region to provide additional support to the communities that were impacted by Hurricane Harvey.for various purposes. In 2017, “A New Century of Service” grants, which celebrate PNM’s 100th anniversary, will fundfunded 62 community projects to build a better future for local communities. In December 2017, PNM announced an additional $1.0 million in donations to the PNM Resources Foundation to support future economic and educational programs in New Mexico. In March 2018, the PNM Resources Foundation awarded five grants of $0.2 million each, to be paid over two years, to the New Mexico State University College of Engineering to support education for professional surveyors and for other economic and development educational opportunities.

PNM provides funds to support for nonprofits in New Mexico focused in the areas of economic development, education, and environmental giving. During 2016, PNM provided $1.0 million to support these areas in communities within New Mexico.the environment. One of PNM’s most important outreach programs is tailored for low incomelow-income customers. In 2016,2017, PNM hosted 4144 community events throughout its service territory to connect low-income customers with nonprofit community service providers offering support and help with such needs as water and gas utility bills, food, clothing, medical programs, and services for seniors, and weatherization. PNM has hosted 30 similar events in the first nine months of 2017.seniors. Additionally, through its Good Neighbor Fund, PNM provided $0.5 million of assistance with electric bills to 3,7703,804 families in 20162017 and offered financial literacy training to further support customers.

Volunteerism is an important facet of the PNMR culture. In 2016,2017, more than 750800 PNM and TNMP employees and retirees contributed approximately 9,00010,800 volunteer hours serving their local communities. Company volunteers also actively participate on nonprofit boards, in educational, economic, and environmental forums, as well as safety seminars. PNMR employees are, in large part, responsible for the success of the Company’s customer, stakeholder, and community outreach.
Economic Factors
PNM – In the three and ninesix months ended SeptemberJune 30, 20172018, PNM experienced decreasesan increase in weather normalizedweather-normalized retail load of 0.9%1.0% and 0.7%a decrease in weather-normalized retail load of 0.1% compared to 2016, primarily due to decreased commercial2017, reflecting New Mexico’s overall economy,

along with PNM’s successful energy efficiency programs and industrial sales, reflecting a continued sluggishincreases in distributed generation. However, it appears the New Mexico economy is strengthening as there is growth in New Mexico. However, economic conditionspersonal income and the state’s finances are stronger. Employment growth in Albuquerque appearis rising and coming closer to be stabilizingthe national average as the state continues efforts to spur economic growth and even improving in certain areas, as evidenced by continuing upticksattract jobs. PNM’s customer growth of 0.8% and 0.8% in the number of residential housing salesthree and prices. The Albuquerque metro area is showing employment growth, but continues to be lower than the national average. Also,six months ended June 30, 2018 reflects these factors, including some of the previously announced successful economic development efforts, such as the selection of a site within PNM’s New Mexico service territory for a data center by Facebook Inc., appear to have started their hiring process. There also have been some expansions of existing businesses, particularly in healthcare, education, and professional services. The economy in New Mexico continues to have mixed indicators and experience softness that is driven primarily by low oil and natural gas prices. Although PNM does not serve the regions of the state that produce oil and gas, it is anticipated that the impacts of layoffs and the decrease in state royalty revenues will further soften the economies in PNM’s service territory, particularly in the Albuquerque metropolitan area and Santa Fe, as the state deals with budget shortfalls.efforts.
TNMP – In the ninethree and six months ended SeptemberJune 30, 20172018, TNMP experienced an increase in volumetric weather normalized retail load of 1.7%1.4% and 2.5% compared to 2016 although load in the three months ended September 30, 2017 was unchanged.2017. Most of TNMP’s industrial and larger commercial customers are billed based on their peak demand. Demand-based load, excluding retail transmission customers, increased 3.3%7.0% and 4.3%6.2% in the three and ninesix months ended SeptemberJune 30, 2017. The2018. Economic and business growth in Texas economy continues to grow, primarily due to its diverse base, which helps compensate foroutpace the weaknessrest of the country. Texas led the nation in job creation in the energy sector, as well as offsetting somefirst quarter of the impacts of Hurricane Harvey. Because TNMP’s service territory is geographically dispersed and was largely on the edges of the storm, a smaller percentage of customers were impacted by the hurricane as compared to some other utilities. The relocation of some national and global corporate headquarters to the Dallas-Fort Worth area has led to growth in commercial customers and also contributes to

growth in residential and small business customers.2018. TNMP continues to addsee strong demand in its service territories, particularly with new transmission customersinterconnection requests in itsthe West Texas service territoryregion where oil and gas production continues to grow.grow and in the Gulf Coast area for load additions related to petroleum refineries.
Results of Operations
Net earnings attributable to PNMR were $134.2$53.2 million, or $1.67$0.67 per diluted share in the ninesix months ended SeptemberJune 30, 20172018 compared to $92.0$60.4 million, or $1.15$0.75 per diluted share, in 2016.2017. Among other things, earnings in the ninesix months ended SeptemberJune 30, 2017, as compared to 2016,2018 benefited from additional revenues due to the rate increase approved in the NM 20152016 Rate Case at PNM, higher revenues underfrom new transmission customers and FERC formula transmission rates and new transmission customers at PNM, rate increases and increased load at TNMP, lowerwarmer weather at PNM and TNMP in the second quarter of 2018 and colder weather at TNMP in the first quarter of 2018, higher AFUDC, and reduced income tax expense due to the reduced federal corporate income tax rate and the amortization of excess deferred income taxes ordered by the NMPRC. These increases were more than offset by reduced revenues at PNM due to power from PVNGS Unit 3 not being sold into the wholesale market, higher plant maintenance costs at PNM, higher AFUDCincreased operating expense due to higher levelsthe additional 197 MW of construction expenditures at PNM, excess tax benefits related to stock compensation recognized under a new accounting standard (Note 8),ownership in SJGS Unit 4 (offset by reduced expenses from the shutdown of SJGS Units 2 and PNM not having regulatory disallowances in 2017. These increases were partially offset by decreased load at PNM, milder weather at PNM and TNMP, lower revenue from NEC at PNM,3), increased depreciation and property taxes due to increased plant in service at PNM and TNMP, and higher depreciation rates approved in PNM’s NM 2015 Rate Case, and lower interest incomegains on the Westmoreland Loan and from the IRS, as well as the additional income taxes on increased earnings.sales of investment securities at PNM. Additional information on factors impacting results of operation for each segment is discussed under Results of Operations below.
Liquidity and Capital Resources

PNMR and PNM have revolving credit facilities that expire in October 2021.2022. In July 2018, the PNMR Revolving Credit Facility was amended to provide for two one-year extension options, subject to approval by a majority of the lenders. The PNMR and PNM facilities have capacities of $300.0 million and $400.0 million through October 2020 and $290.0 million and $360.0 million from November 2020 through October 2021.2022. Both facilities provide for short-term borrowings and letters of credit. In addition, PNM has a $50.0$40.0 million revolving credit facility, which expires in January 2018,December 2022, with banks having a significant presence in New Mexico and TNMP has a $75.0 million revolving credit facility, which expires in September 2022. On February 26, 2018, PNMR Development entered into a $24.5 million revolving credit facility that matures on February 25, 2019. Total availability for PNMR on a consolidated basis was $635.0$669.9 million at October 20, 2017.July 25, 2018. 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.

PNMR projects that its consolidated capital requirements, consisting of construction expenditures and dividends, will total $2,961.9$3,150.0 million for 2017-2021,2018-2022, including amounts expended through SeptemberJune 30, 2017.2018. The construction expenditures include estimated amounts for environmental upgrades at Four Corners, the 30 MW of new solar capacity to supply power to a new data center being constructed by Facebook Inc., 50 MW of new solar facilities included in PNM’s 2018 renewable energy procurement plan, an anticipated expansion of PNM’s transmission system, and the initial costs of replacement resources related to the potential shutdown of SJGS Units 1 and 4 in 2022. See Note 12.

In July 2017, PNM entered into the $200.0 million PNM 2017 Term Loan Agreement and repaid the $175.0 million PNM 2016 Term Loan with part of the proceeds. Also in July 2017, PNM entered into the PNM 2017 Senior Unsecured Note Agreement, under which $450.0 million of the PNM 2018 SUNs arewere to be issued in 2018 andwith the proceeds willto be used to repay $450.0 million of currently outstanding Senior Unsecured NotesSUNs on their maturity dates indates. In May 2018, PNM issued $350.0 million of the PNM 2018 SUNs and the remaining $100.0 million were issued on July 31, 2018. In March 2018, PNMR issued $300.0 million of 3.25% SUNs (the “PNMR 2018 SUNs”), which will mature on March 9, 2021. Proceeds from the issuance of the PNMR 2018 SUNs were used to repay a $150.0 million term loan and borrowings under the PNMR Revolving Credit Facility. On June 28, 2018, TNMP issued $60.0 million of first mortgage bonds maturing on June 28, 2028 and used the proceeds to reduce borrowings under the TNMP Revolving Credit Facility. On July 25, 2018, TNMP entered into the $20.0 million TNMP 2018 Term Loan Agreement that is due on July 25, 2020 and used the proceeds to reduce short-term borrowings and for general corporate purposes. After considering the effects of those financings,

PNMR has consolidated maturities mandatory remarketings, and other repayments of short-term and long-term debt aggregating $265.7$572.3 million in the period from OctoberApril 1, 20172018 through September 30, 2018 and $102.3 million in the remainder of 2018.March 31, 2019. Furthermore, the $50.0$24.5 million PNM New Mexico Credit FacilityPNMR Development revolving credit facility expires in January 2018.February 2019. 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 2017-20212018-2022 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.requirements for at least the next twelve months. The Company is in compliance with its debt covenants.

RESULTS OF OPERATIONS

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.

A summary of net earnings attributable to PNMR is as follows:
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended June 30, Six Months Ended June 30,
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
(In millions, except per share amounts)(In millions, except per share amounts)
Net earnings attributable to PNMR$73.7
 $54.4
 $19.3
 $134.2
 $92.0
 $42.2
$38.2
 $37.6
 $0.6
 $53.2
 $60.4
 $(7.2)
Average diluted common and common equivalent shares80.2
 80.1
 0.1
 80.1
 80.1
 —
80.0
 80.1
 (0.1) 80.0
 80.1
 (0.1)
Net earnings attributable to PNMR per diluted share$0.92
 $0.68
 $0.24
 $1.67
 $1.15
 $0.52
$0.48
 $0.47
 $0.01
 $0.67
 $0.75
 $(0.08)

The components of the change in net earnings attributable to PNMR are:
Three Months Ended Nine Months EndedThree Months Ended Six Months Ended
September 30, 2017 September 30, 2017June 30, 2018 June 30, 2018
(In millions)(In millions)
PNM$19.8
 $43.1
$(0.3) $(9.1)
TNMP0.8
 2.7
3.2
 5.0
Corporate and Other(1.4) (3.7)(2.3) (3.1)
Net change$19.3
 $42.2
$0.6
 $(7.2)

Information regarding the factors impacting PNMR’s operating results by segment are set forth below.

Segment Information

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

PNM

PNM’sPNM defines utility margin is defined as electric operating revenues less cost of energy, which consists primarily of fuel and purchase power costs. PNM believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since substantially all fuel and purchase power costs are offset in revenues as those costs are passed through to customers under PNM’s FPPAC. Utility margin is not a financial measure required to be presented under GAAP and is considered a non-GAAP measure.


The following table summarizes the operating results for PNM:
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended June 30, Six Months Ended June 30,
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
(In millions)(In millions)
Electric operating revenues$327.3
 $311.3
 $16.0
 $854.9
 $780.2
 $74.7
$264.5
 $276.1
 $(11.6) $500.7
 $527.7
 $(27.0)
Cost of energy82.4
 88.6
 (6.2) 246.6
 222.4
 24.2
66.4
 83.0
 (16.6) 137.2
 164.3
 (27.1)
Utility margin244.9
 222.7
 22.2
 608.3
 557.9
 50.4
198.2
 193.1
 5.1
 363.6
 363.4
 0.2
Operating expenses94.9
 109.3
 (14.4) 288.3
 315.0
 (26.7)107.1
 95.4
 11.7
 207.6
 189.2
 18.4
Depreciation and amortization36.8
 33.3
 3.5
 109.2
 97.8
 11.4
38.2
 36.4
 1.8
 74.8
 72.5
 2.3
Operating income113.3
 80.1
 33.2
 210.7
 145.1
 65.6
52.9
 61.3
 (8.4) 81.2
 101.8
 (20.6)
Other income (deductions)8.1
 6.5
 1.6
 26.4
 25.9
 0.5
0.2
 5.6
 (5.4) 3.9
 14.0
 (10.0)
Interest charges(20.5) (22.2) 1.7
 (62.4) (66.5) 4.1
(20.0) (20.9) 0.9
 (40.8) (41.9) 1.1
Segment earnings before income taxes100.9
 64.3
 36.6
 174.7
 104.5
 70.2
33.1
 46.0
 (12.9) 44.3
 73.8
 (29.5)
Income (taxes)(35.6) (19.3) (16.3) (58.9) (32.1) (26.7)(2.3) (15.5) 13.2
 (2.0) (23.2) 21.2
Valencia non-controlling interest(4.5) (4.0) (0.5) (11.5) (11.0) (0.5)(4.1) (3.5) (0.6) (7.8) (7.0) (0.8)
Preferred stock dividend requirements(0.1) (0.1) —
 (0.4) (0.4) —
(0.1) (0.1) —
 (0.3) (0.3) —
Segment earnings$60.7
 $40.9
 $19.8
 $104.0
 $60.9
 $43.1
$26.5
 $26.8
 $(0.3) $34.2
 $43.3
 $(9.1)


The following table shows total GWh sales, including the impacts of weather, by customer class and average number of customers:
Three Months Ended September 30, 
Nine Months Ended
September 30,
Three Months Ended June 30, Six Months Ended June 30,
    Percentage     Percentage    Percentage     Percentage
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
(Gigawatt hours, except customers)(Gigawatt hours, except customers)
Residential978.5
 967.9
 1.1 % 2,439.0
 2,468.6
 (1.2)%747.4
 711.0
 5.1 % 1,499.1
 1,460.6
 2.6 %
Commercial1,058.6
 1,063.5
 (0.5) 2,883.4
 2,921.7
 (1.3)1,017.1
 998.1
 1.9
 1,851.5
 1,824.8
 1.5
Industrial218.4
 223.9
 (2.5) 640.5
 658.8
 (2.8)210.1
 214.1
 (1.9) 415.8
 422.0
 (1.5)
Public authority73.2
 73.9
 (0.9) 189.1
 187.3
 1.0
61.2
 62.7
 (2.4) 111.5
 115.9
 (3.8)
Economy energy service (1)
174.8
 197.5
 (11.5) 542.8
 610.2
 (11.0)172.3
 181.3
 (5.0) 343.0
 368.0
 (6.8)
Firm-requirements wholesale (2)
22.1
 100.1
 (77.9) 65.5
 324.7
 (79.8)—
 21.8
 (100.0) —
 43.4
 (100.0)
Other sales for resale (3)
821.7
 727.6
 12.9
 2,731.7
 1,997.4
 36.8
479.2
 824.6
 (41.9) 1,160.2
 1,910.0
 (39.3)
3,347.3
 3,354.4
 (0.2)% 9,492.0
 9,168.7
 3.5 %2,687.3
 3,013.6
 (10.8)% 5,381.1
 6,144.7
 (12.4)%
Average retail customers (thousands)522.3
 519.0
 0.6 % 521.6
 518.2
 0.7 %525.8
 521.5
 0.8 % 525.3
 521.3
 0.8 %

(1) PNM purchases energy for a large customer 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 only a minor impact in utility margin resulting from providing ancillary services.

(2) Decrease in 20172018 reflects reduced sales to NEC (Note 12) andthe loss of other firm-requirementsNEC as a wholesale customers.generation customer.

(3) IncreaseDecrease in 2018 reflects that PVNGS Unit 3 is included as a New Mexico jurisdictional resource beginning January 1, 2018 rather than as merchant plant in 2017 includes the hazard sharing agreement with Tri-State (Note 12)11). Increase is also due to more power available for off-system sales, primarily related to SJGS and Four Corners, as well as power that was previously sold to NEC and other firm-requirements wholesale customers. Substantially all of the margin from off-system sales is returned to customers through the FPPAC.


Operating Results – Three months ended SeptemberJune 30, 20172018 compared to 20162017

The following table summarizes the significant changes to utility margin:
   
Three Months Ended
September 30, 2017
   Change
Utility margin: (In millions)
    
 
Rate relief – Additional revenue due to rate increase approved by the NMPRC on September 28, 2016 and certain fuel costs being passed through the FPPAC
 $20.1
 
Customer usage/load – PNM’s weather normalized retail KWh sales decreased 0.9%, primarily in commercial and industrial sales
 (1.7)
 
Weather – Warmer weather; cooling degree days were 3.7% higher
 2.0
 
Transmission – Higher revenues under formula transmission rates and addition of new customers
 4.4
 
Wholesale contracts – Primarily due to NEC (Note 12)
 (2.0)
 
Unregulated margin – Higher hedged prices for PVNGS Unit 3 power sales
 1.3
 
Net unrealized economic hedges – Primarily related to hedges of PVNGS Unit 3 power sales
 (2.9)
 Other 1.0
 Net Change $22.2
   Three Months Ended
June 30, 2018
   Change
Utility margin: (In millions)
    
 
Rate relief – Additional revenue due to rate increase approved by the NMPRC effective February 1, 2018 (Note 12)
 $0.9
 
Retail Customer usage/load – Weather normalized KWh sales increased 1.0% due to increased sales to residential, commercial, and industrial customers
 1.6
 
Weather – Warmer weather in 2018; cooling degree days were 35.6% higher
 3.7
 
Transmission – The addition of new customers and higher revenues under formula transmission rates
 4.0
 
Wholesale contracts – Loss of NEC as a wholesale generation customer
 (0.6)
 
Unregulated margin – Loss of PVNGS Unit 3 wholesale power sales
 (5.2)
 
Third party transmission cost – Transmission of power from PVNGS Unit 3 to serve New Mexico retail customers
 (1.7)
 
Rate riders – Includes renewable energy and energy efficiency riders, which are partially offset in operating expenses, depreciation and amortization, and interest charges
 0.2
 
Net unrealized economic hedges – Primarily related to 2017 hedges of PVNGS Unit 3 power sales and sales to NEC
 2.3
 Other (0.1)
 Net Change $5.1

The following tables summarize the primary drivers for changes in operating expenses, depreciation and amortization, other income (deductions), interest charges, and income taxes:
   Three Months Ended
September 30, 2017
   Change
Operating expenses: (In millions)
   
 2016 regulatory disallowance due to the NMPRC’s September 28, 2016 order in PNM’s NM 2015 Rate Case (Note 12) $(11.3)
 2016 regulatory disallowance due to change in estimated write-offs associated with the SJGS BART determination and ownership restructuring (Note 11) (5.2)
 Higher capitalized administrative and general expenses due to higher construction spending (0.3)
 Lower employee related expenses and outside consulting costs (0.3)
 Higher allocated corporate depreciation, primarily related to computer software 1.7
 Higher plant maintenance costs 1.0
 Net Change $(14.4)
   Three Months Ended
June 30, 2018
   Change
Operating expenses: (In millions)
   
 Higher plant maintenance costs at SJGS, Four Corners, and gas-fired plants $9.2
 Increased costs associated with additional 132 MW of SJGS Unit 4 and accelerated recovery of SNCRs on SJGS Units 1 and 4 3.7
 2018 regulatory disallowance resulting from the NMPRC’s September 28, 2016 order in PNM’s NM 2015 Rate Case (Note 12) 1.8
 Increased costs associated with 65 MW of SJGS Unit 4 held as merchant plant beginning January 1, 2018 (Note 11) 1.4
 Higher property taxes due to increases in utility plant in service and higher assessed values 1.0
 Lower capitalized administrative and general expenses due to lower construction spending in 2018 0.2
 Cost savings realized from the retirement of SJGS Units 2 and 3 (4.2)
 2017 training costs associated with new software implementation (0.3)
 Other (1.1)
 Net Change $11.7

   Three Months Ended
September 30, 2017
   Change
Depreciation and amortization: (In millions)
   
 Higher depreciation rates approved by the NMPRC in PNM’s 2015 NM Rate Case $2.5
 Increased utility plant in service 1.2
 Other (0.2)
 Net Change $3.5

   Three Months Ended
June 30, 2018
   Change
Depreciation and amortization: (In millions)
   
 Increased utility plant in service $2.5
 Lower depreciation resulting from the retirement of SJGS Units 2 and 3, partially offset by amortization of the associated regulatory asset (Note 11) (1.0)
 Other 0.3
 Net Change $1.8
Other income (deductions):  
   
 Higher equity AFUDC, primarily due to increased levels of construction expenditures $1.7
 Higher gains on available-for-sale securities in the NDT and coal mine reclamation trusts 0.9
 Lower trust expenses related to the NDT and coal mine reclamation trusts, partially offset by higher interest income 0.2
 Lower income from “refined coal” (a third-party pre-treatment process); income is now passed through to customers as ordered in PNM’s NM 2015 Rate Case (1.3)
 Other 0.1
 Net Change $1.6
Other income (deductions):  
   
 Lower gains on investment securities in the NDT and coal mine reclamation trusts, including the impact of a new accounting pronouncement (Note 7) $(7.3)
 Lower non-service components of pension and OPEB expense 0.9
 Higher interest income related to investment securities in the NDT and coal mine reclamation trusts, partially offset by higher trust expenses 0.6
 Other 0.4
 Net Change $(5.4)
Interest charges:  
   
 Lower interest on $146.0 million of PCRBs refinanced in September 2016 $0.9
 Lower interest on $57.0 million of PCRBs refinanced in June 2017 0.2
 Lower short term debt borrowings 0.3
 Higher debt AFUDC as a result of higher construction spending 0.5
 Other (0.2)
 Net Change $1.7
Interest charges:  
   
 Lower interest on $350.0 million of SUNs refinanced in May 2018 $1.8
 Lower interest on $57.0 million of PCRBs refinanced in June 2017 0.2
 Higher debt AFUDC 0.2
 Higher interest on term loan agreements (0.6)
 Interest on deposit by PNMR Development for potential transmission interconnections (0.7)
 Net Change $0.9
Income taxes:  
   
 Increase due to higher segment earnings before income taxes $(14.0)
 2016 regulatory recovery of prior year impairment of state net operating loss carryforward (2.1)
 Decrease due to excess tax benefits related to stock compensation awards (Note 8) 0.1
 Other (0.3)
 Net Change $(16.3)
Income taxes:  
   
 Decrease due to reduction in corporate income tax rate and lower segment earnings before income taxes $9.1
 Amortization of excess deferred income taxes, as ordered by the NMPRC in PNM’s NM 2016 Rate Case 4.6
 Increase due to lower excess tax benefits related to stock compensation awards (Note 8) (0.2)
 Other (0.3)
 Net Change $13.2


Operating Results – NineSix months ended SeptemberJune 30, 20172018 compared to 20162017

The following table summarizes the significant changes to utility margin:
   
Nine Months Ended
September 30, 2017
   Change
Utility margin: (In millions)
    
 
Rate relief – Additional revenue due to rate increase approved by the NMPRC on September 28, 2016 and certain fuel costs being passed through the FPPAC
 $51.9
 
Customer usage/load – PNM’s weather normalized retail KWh sales decreased 0.7%, primarily in commercial and industrial sales
 (2.7)
 
Weather – Milder weather; heating degree days were 12.2% lower, partially offset by higher cooling degree days of 1.5%
 (2.1)
 
Leap Year – Decrease in revenue due to additional day in 2016
 (1.6)
 
Transmission – Higher revenues under formula transmission rates and addition of new customers
 8.3
 
Wholesale contracts – Primarily due to NEC (Note 12)
 (7.1)
 
Unregulated margin – Higher hedged prices for PVNGS Unit 3 power sales
 3.1
 
Rate riders – Includes renewable energy and energy efficiency riders
 (1.4)
 
Net unrealized economic hedges – Primarily related to hedges of PVNGS Unit 3 power sales
 1.3
 Other 0.7
 Net Change $50.4

   Six Months Ended
June 30, 2018
   Change
Utility margin: (In millions)
    
 
Rate relief – Additional revenue due to rate increase approved by the NMPRC effective February 1, 2018 (Note 12)
 $1.5
 
Retail Customer usage/load – Weather normalized KWh sales decreased 0.1% due to decreased sales to residential, industrial, and other customers
 (0.2)
 
Weather – Warmer weather in 2018; cooling degree days were 35.4% higher
 5.8
 
Transmission – The addition of new customers and higher revenues under formula transmission rates
 6.8
 
Wholesale contracts – Loss of NEC as a wholesale generation customer
 (1.1)
 
Unregulated margin – Loss of PVNGS Unit 3 wholesale power sales
 (11.4)
 
Third party transmission cost – Transmission of power from PVNGS Unit 3 to serve New Mexico retail customers
 (3.6)
 
Rate riders – Includes renewable energy and energy efficiency riders, which are partially offset in operating expenses, depreciation and amortization, and interest charges
 0.8
 
Net unrealized economic hedges – Primarily related to 2017 hedges of PVNGS Unit 3 power sales and sales to NEC
 1.0
 Other 0.6
 Net Change $0.2

The following tables summarize the primary drivers for changes in operating expenses, depreciation and amortization, other income (deductions), interest charges, and income taxes:
   Nine Months Ended
September 30, 2017
   Change
Operating expenses: (In millions)
   
 2016 regulatory disallowance due to the NMPRC’s September 28, 2016 order in PNM’s NM 2015 Rate Case (Note 12) $(11.3)
 2016 regulatory disallowance due to change in estimated write-offs associated with the SJGS BART determination and ownership restructuring (Note 11) (5.9)
 Lower plant maintenance costs (9.3)
 Lower employee related expenses and outside consulting costs (3.9)
 Lower rent expense associated with PVNGS leases (Note 6) (0.9)
 Higher capitalized administrative and general expenses due to higher construction spending (0.9)
 Lower bad debt expense, primarily related to the bankruptcy of an industrial customer in 2016 (0.4)
 Higher allocated corporate depreciation, primarily related to computer software 4.4
 Training costs associated with new software implementation 1.1
 Higher property taxes due to increased utility plant in service 0.6
 Higher environmental expenses 0.5
 Other (0.7)
 Net Change $(26.7)
Depreciation and amortization:  
   
 Higher depreciation rates approved by the NMPRC in PNM’s 2015 NM Rate Case $6.1
 Increased utility plant in service 5.9
 Other (0.6)
 Net Change $11.4

   Six Months Ended
June 30, 2018
   Change
Operating expenses: (In millions)
   
 Higher plant maintenance costs at SJGS, Four Corners, and gas-fired plants $14.3
 Increased costs associated with additional 132 MW of SJGS Unit 4 and accelerated recovery of SNCRs on SJGS Units 1 and 4 7.0
 Increased costs associated with 65 MW of SJGS Unit 4 held as merchant plant beginning January 1, 2018 (Note 11) 2.7
 Higher property taxes due to increases in utility plant in service and higher assessed values 1.7
 Higher employee medical expenses due to unfavorable claims experience 0.6
 2018 regulatory disallowance resulting from the NMPRC’s September 28, 2016 order in PNM’s NM 2015 Rate Case (Note 12) 1.8
 Lower capitalized administrative and general expenses due to lower construction spending in 2018 0.7
 Cost savings realized from the retirement of SJGS Units 2 and 3 (9.4)
 2017 training costs associated with new software implementation (1.1)
 Other 0.1
 Net Change $18.4

Other income (deductions):  
   
 Higher equity AFUDC, primarily due to increased levels of construction expenditures $3.3
 Higher gains on available-for-sale securities in the NDT and coal mine reclamation trusts 2.4
 
Higher interest income related to the NDT and coal mine reclamation trusts, partially offset by lower trust expenses

 0.4
 Interest income from third party transmission service provider due to FERC ruling 1.0
 Lower income from “refined coal” (a third-party pre-treatment process); income is now passed through to customers as ordered in PNM’s NM 2015 Rate Case (3.8)
 2016 interest income from IRS, net of related expenses (Note 13) (2.9)
 Other 0.1
 Net Change $0.5

   Six Months Ended
June 30, 2018
   Change
Depreciation and amortization: (In millions)
   
 Increased utility plant in service $4.3
 Lower depreciation resulting from the retirement of SJGS Units 2 and 3, partially offset by amortization of the associated regulatory asset (Note 11) (2.6)
 Other 0.6
 Net Change $2.3
   Nine Months Ended
September 30, 2017
   Change
Interest charges: (In millions)
   
 Lower interest on $146.0 million of PCRBs refinanced in September 2016 $2.6
 Lower interest on $57.0 million of PCRBs refinanced in June 2017 0.3
 Lower short term debt borrowings 0.7
 Higher debt AFUDC as a result of higher construction spending 0.4
 Other 0.1
 Net Change $4.1
Other income (deductions):  
   
 Lower gains on investment securities in the NDT and coal mine reclamation trusts, including the impact of a new accounting pronouncement (Note 7) $(13.7)
 Higher equity AFUDC 0.5
 2017 interest income from third-party transmission service provider due to FERC ruling (1.0)
 Lower non-service components of pension and OPEB expense 2.3
 Higher interest income related to investment securities in the NDT and coal mine reclamation trusts, partially offset by higher trust expenses 1.4
 Other 0.5
 Net Change $(10.0)
Income taxes:  
   
 Increase due to higher segment earnings before income taxes $(27.1)
 Regulatory recovery of prior year impairment of state net operating loss carryforward due to the NMPRC’s September 28, 2016 order in PNM’s NM 2015 Rate Case (Note 12) (2.1)
 Impacts of phased-in reduction in New Mexico corporate income tax rates 0.8
 Decrease due to excess tax benefits related to stock compensation awards (Note 8) 1.7
 Net Change $(26.7)
Interest charges:  
   
 Lower interest on $350.0 million of SUNs refinanced in May 2018 $1.8
 Lower interest on $57.0 million of PCRBs refinanced in June 2017 0.5
 Higher debt AFUDC 0.6
 Higher interest on term loan agreements (1.2)
 Interest on deposit by PNMR Development for potential transmission interconnections (0.7)
 Other 0.1
 Net Change $1.1
Income taxes:  
   
 Decrease due to reduction in corporate income tax rate and lower segment earnings before income taxes $16.7
 Amortization of excess deferred income taxes, as ordered by the NMPRC in PNM’s NM 2016 Rate Case 5.8
 Increase due to lower excess tax benefits related to stock compensation awards (Note 8) (0.5)
 Other (0.8)
 Net Change $21.2


TNMP

TNMP’sTNMP defines utility margin is defined as electric operating revenues less cost of energy, which consists of costs charged by third-party transmission providers. TNMP believes that utility margin provides a more meaningful basis for evaluating operations

than electric operating revenues since all third-party transmission costs are passed on to consumers through a transmission cost recovery factor. Utility margin is not a financial measure required to be presented under GAAP and is considered a non-GAAP measure.

The following table summarizes the operating results for TNMP:
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended June 30, Six Months Ended June 30,
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
(In millions)(In millions)
Electric operating revenues$92.6
 $89.1
 $3.5
 $257.5
 $246.5
 $11.0
$87.8
 $86.2
 $1.6
 $169.4
 $164.8
 $4.6
Cost of energy21.4
 20.2
 1.2
 64.2
 60.1
 4.1
21.4
 21.3
 0.1
 43.1
 42.8
 0.3
Utility margin71.3
 68.9
 2.4
 193.3
 186.4
 6.9
66.5
 64.9
 1.6
 126.3
 122.0
 4.3
Operating expenses25.4
 24.2
 1.2
 72.2
 70.3
 1.9
23.5
 23.0
 0.5
 48.5
 46.8
 1.7
Depreciation and amortization16.4
 16.4
 —
 47.4
 45.8
 1.6
16.1
 15.6
 0.5
 32.5
 31.0
 1.5
Operating income29.5
 28.4
 1.1
 73.7
 70.3
 3.4
26.8
 26.3
 0.5
 45.4
 44.3
 1.1
Other income (deductions)1.2
 0.9
 0.3
 2.4
 2.1
 0.3
0.8
 0.4
 0.4
 1.9
 1.2
 0.7
Interest charges(7.7) (7.3) (0.4) (22.6) (22.2) (0.4)(7.8) (7.5) (0.3) (15.5) (14.9) (0.6)
Segment earnings before income taxes23.0
 21.9
 1.1
 53.5
 50.3
 3.2
19.9
 19.2
 0.7
 31.7
 30.5
 1.2
Income (taxes)(8.3) (8.1) (0.2) (19.0) (18.5) (0.5)(4.5) (7.0) 2.5
 (7.0) (10.7) 3.7
Segment earnings$14.7
 $13.9
 $0.8
 $34.5
 $31.8
 $2.7
$15.4
 $12.2
 $3.2
 $24.8
 $19.8
 $5.0

The following table shows total sales, including the impacts of weather, by retail tariff consumer class and average number of consumers:

Three Months Ended September 30, 
Nine Months Ended
September 30,
Three Months Ended June 30, Six Months Ended June 30,
    Percentage     Percentage    Percentage     Percentage
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
Volumetric load (1) (GWh)
  
Residential983.8
 1,032.5
 (4.7)% 2,295.2
 2,314.2
 (0.8)%790.2
 734.4
 7.6 % 1,447.0
 1,311.4
 10.3 %
Commercial and other8.2
 10.8
 (24.1) 25.8
 32.6
 (20.9)7.9
 8.5
 (7.1) 16.0
 17.7
 (9.6)
Total volumetric load992.0
 1,043.3
 (4.9)% 2,321.0
 2,346.8
 (1.1)%798.1
 742.9
 7.4 % 1,463.0
 1,329.1
 10.1 %
Demand-based load (2) (MW)
4,443.6
 3,968.5
 12.0 % 12,359.8
 11,392.5
 8.5 %4,342.7
 4,044.6
 7.4 % 8,652.9
 7,916.2
 9.3 %
Average retail consumers (thousands) (3)
249.0
 245.9
 1.3 % 247.9
 244.9
 1.2 %251.2
 247.9
 1.3 % 250.6
 247.3
 1.3 %

(1) Volumetric load consumers are billed on KWh usage.

(2) Demand-based load includes consumers billed on monthly KW peak and also includes retail transmission customers that are primarily billed under TNMP’s rate riders.

(3) TNMP provides transmission and distribution services to REPs that provide electric service to their customers 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.


Operating Results – Three months ended SeptemberJune 30, 20172018 compared to 20162017

The following table summarizes the significant changes to utility margin:
   
Three Months Ended
September 30, 2017
   Change
Utility margin: (In millions)
    
 
Rate relief – Transmission cost of service rate increases in September 2016, March 2017, and September 2017
 $1.8
 
Retail customer usage/load – Weather normalized usage per retail customer decreased 1.3%; the average number of retail consumers increased 1.3%
 (0.1)
 
Demand based customer usage/load – Higher demand-based revenues for large commercial and industrial retail consumers; billed demand, excluding retail transmission customers, increased 3.3%
 1.9
 
Wholesale transmission load – Increased coincidental peak load for third-party transmission customers

 0.3
 
Weather – Milder weather in 2017; cooling degree days were 7.6% lower in 2017
 (1.1)
 Other (0.4)
 Net Change $2.4
   Three Months Ended
June 30, 2018
   Change
Utility margin: (In millions)
    
 
Rate relief – Transmission cost of service rate increases in September 2017 and March 2018
 $1.0
 
Retail customer usage/load – Weather normalized KWh sales increased 1.4%; the average number of retail consumers increased 1.3%
 0.1
 
Demand based customer usage/load – Higher demand-based revenues for large commercial and industrial retail consumers; billed demand, excluding retail transmission customers, increased 7.0%
 1.0
 
Weather – Warmer weather in 2018; cooling degree days were 7.9% higher in 2018
 1.0
 
Rate Riders – Impacts of rate riders, including the AMS surcharge, CTC surcharge, energy efficiency rider, and transmission cost recovery factor
 (0.3)
 
Revenue subject to refund – Amounts deferred as a regulatory liability for the impact of the reduction in the federal corporate income tax rate (Note 12)
 (1.2)
 Net Change $1.6

The following tables summarize the primary drivers for changes in operating expenses, depreciation and amortization, other income (deductions), interest charges, and income taxes:
   Three Months Ended
June 30, 2018
   Change
Operating expenses: (In millions)
   
 Higher employee related expenses $0.1
 Higher outside consulting costs, including vegetation management 0.4
 Higher capitalization of administrative and general expenses due to higher construction expenditures (1.1)
 Higher property taxes due to increased utility plant in service 0.4
 Higher property and casualty expense, primarily due to unfavorable claims experience 0.4
 Other 0.3
 Net Change $0.5
Depreciation and amortization:  
   
 Increased utility plant in service $1.0
 Reduced CTC amortization and AMS depreciation (0.5)
 Net Change $0.5
Other income (deductions):  
   
 Higher equity AFUDC $0.3
 Other 0.1
 Net Change $0.4

   Three Months Ended
June 30, 2018
   Change
Interest charges: (In millions)
   
 Increase due to issuance of $60.0 million of long-term debt in August 2017 $(0.5)
 Higher debt AFUDC 0.3
 Other (0.1)
 Net Change $(0.3)
Income taxes:  
   
 Decrease due to reduction in corporate income tax rate, partially offset by tax on higher segment earnings $2.6
 Increase due to lower excess tax benefits related to stock compensation awards (Note 8) (0.1)
 Net Change $2.5

Operating Results – Six months ended June 30, 2018 compared to 2017

The following table summarizes the significant changes to utility margin:
   Six Months Ended
June 30, 2018
   Change
Utility margin: (In millions)
    
 
Rate relief – Transmission cost of service rate increases in March 2017, September 2017, and March 2018
 $2.7
 
Retail customer usage/load – Weather normalized KWh sales increased 2.5%; the average number of retail consumers increased 1.3%
 0.6
 
Demand based customer usage/load – Higher demand-based revenues for large commercial and industrial retail consumers; billed demand, excluding retail transmission customers, increased 6.2%
 1.9
 
Weather – Milder weather in 2017 than 2018; heating degree days were 72.2% higher in the first quarter of 2018 and cooling degree days were 7.9% higher in the second quarter of 2018
 2.1
 
Revenue subject to refund – Amounts deferred as a regulatory liability for the impact of the reduction in the federal corporate income tax rate (Note 12)
 (2.7)
 Other (0.3)
 Net Change $4.3


The following tables summarize the primary drivers for changes in operating expenses, depreciation and amortization, other income (deductions), interest charges, and income taxes:
   Three Months Ended
September 30, 2017
   Change
Operating expenses: (In millions)
   
 Higher allocated corporate depreciation, primarily related to computer software $0.6
 Higher outside consulting costs, including vegetation management 0.6
 Lower capitalization of administrative and general expenses due to lower construction expenditures 0.5
 Higher costs that are collected through rate riders 0.2
 Higher property taxes due to increased utility plant in service 0.2
 2016 lease abandonment costs associated with building consolidation efforts (1.0)
 Other 0.1
 Net Change $1.2
   Six Months Ended
June 30, 2018
   Change
Operating expenses: (In millions)
   
 Higher employee related expenses $0.4
 Higher outside consulting costs, including vegetation management 0.8
 Training costs associated with new software implementation in 2017 (0.4)
 Higher costs associated with rate riders, primarily the AMS surcharge 0.4
 Higher property taxes due to increased utility plant in service 0.7
 Higher property and casualty expense, primarily due to unfavorable claims experience 0.4
 Higher allocated corporate depreciation, primarily related to computer software 0.4
 Higher capitalization of administration and general expense due to higher construction expenditures (1.5)
 Other 0.5
 Net Change $1.7
Depreciation and amortization:  
   
 Increased utility plant in service $0.8
 Reduced CTC amortization and AMS depreciation (0.7)
 Other (0.1)
 Net Change $—
Depreciation and amortization:  
   
 Increased utility plant in service $1.9
 Reduced CTC amortization and AMS depreciation (0.4)
 Net Change $1.5
Other income (deductions):  
   
 Higher contributions in aid of construction $0.2
 Other 0.1
 Net Change $0.3
Other income (deductions):  
   
 Higher equity AFUDC $0.6
 Other 0.1
 Net Change $0.7
Interest charges:  
   
 Increase due to issuance of $60.0 million of long-term debt in August 2017 $(0.2)
 Increase due to higher short-term borrowings (0.1)
 Other (0.1)
 Net Change $(0.4)
Interest charges:  
   
 Increase due to issuance of $60.0 million of long-term debt in August 2017 $(1.0)
 Higher debt AFUDC 0.5
 Other (0.1)
 Net Change $(0.6)
Income taxes:  
   
 Increase due to higher segment earnings before income taxes $(0.4)
 Decrease due to excess tax benefits related to stock compensation awards (Note 8) 0.1
 Other 0.1
 Net Change $(0.2)
Income taxes:  
   
 Decrease due to reduction in corporate income tax rate, partially offset by tax on higher segment earnings $4.0
 Increase due to lower excess tax benefits related to stock compensation awards (Note 8) (0.2)
 Other (0.1)
 Net Change $3.7


Operating Results – Nine months ended September 30, 2017 compared to 2016

The following table summarizes the significant changes to utility margin:
   
Nine Months Ended
September 30, 2017
   Change
Utility margin: (In millions)
    
 
Rate relief – Transmission cost of service rate increases in March 2016, September 2016, March 2017, and September 2017
 $4.7
 
Retail customer usage/load – 1.7% increase in weather normalized retail KWh sales, primarily related to the residential class; the average number of retail consumers increased 1.2%
 0.9
 
Demand based customer usage/load – Higher demand-based revenues for large commercial and industrial retail consumers; billed demand, excluding retail transmission customers increased 4.3%
 3.3
 
Wholesale transmission load – Increased coincidental peak load for third-party transmission customers

 0.9
 
Rate riders – Impacts of rate riders, including the AMS surcharge, CTC surcharge, energy efficiency rider, and transmission cost recovery factor
 (1.4)
 
Weather – Milder weather in 2017; heating degree days were 35.8% lower
 (1.4)
 Other (0.1)
 Net Change $6.9

The following tables summarize the primary drivers for changes in operating expenses, depreciation and amortization, other income (deductions), interest charges, and income taxes:
   Nine Months Ended
September 30, 2017
   Change
Operating expenses: (In millions)
   
 Higher allocated corporate depreciation, primarily related to computer software $1.5
 Higher property taxes due to increased utility plant in service 0.7
 Training costs associated with new software implementation 0.4
 2016 lease abandonment costs associated with building consolidation efforts (1.0)
 Other 0.3
 Net Change $1.9
Depreciation and amortization:  
   
 Increased utility plant in service $2.2
 Reduced CTC amortization and AMS depreciation (0.6)
 Net Change $1.6

   Nine Months Ended
September 30, 2017
   Change
Other income (deductions): (In millions)
   
 Higher contribution in aid of construction $0.2
 2016 interest income from IRS, net of related expenses (Note 13) (0.3)
 Other 0.4
 Net Change $0.3
Interest charges:  
   
 Increase due to the issuance of $60.0 million of long-term debt in February 2016 $(0.2)
 Increase due to the issuance of $60.0 million long-term debt in August 2017 (0.2)
 Net Change $(0.4)
Income taxes:  
   
 Increase due to higher segment earnings before income taxes $(1.1)
 Decrease due to excess tax benefits related to stock compensation awards (Note 8) 0.6
 Net Change $(0.5)

Corporate and Other

The table below summarizes the operating results for Corporate and Other:
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended June 30, Six Months Ended June 30,
2017 2016 Change 2017 2016 Change2018 2017 Change 2018 2017 Change
(In millions)(In millions)
Total revenues$—
 $—
 $—
 $—
 $—
 $—
Electric operating revenues$—
 $—
 $—
 $—
 $—
 $—
Cost of energy—
 —
 —
 —
 —
 —
—
 —
 —
 —
 —
 —
Utility margin—
 —
 —
 —
 —
 —
—
 —
 —
 —
 —
 —
Operating expenses(5.4) (3.0) (2.4) (15.3) (9.3) (6.0)(5.4) (5.2) (0.2) (10.4) (9.9) (0.5)
Depreciation and amortization5.6
 3.4
 2.2
 16.2
 10.3
 5.9
5.7
 5.6
 0.1
 11.4
 10.6
 0.8
Operating income (loss)(0.2) (0.3) 0.1
 (0.9) (1.0) 0.1
(0.4) (0.3) (0.1) (1.1) (0.7) (0.4)
Other income (deductions)1.3
 2.9
 (1.6) 5.0
 8.4
 (3.4)0.5
 1.9
 (1.4) 2.2
 3.6
 (1.4)
Interest charges(4.0) (2.9) (1.1) (11.1) (8.5) (2.6)(5.5) (3.9) (1.6) (10.0) (7.2) (2.8)
Segment earnings (loss) before income taxes(2.9) (0.4) (2.5) (7.1) (1.2) (5.9)(5.4) (2.3) (3.1) (8.9) (4.2) (4.7)
Income (taxes) benefit1.2
 0.1
 1.1
 2.7
 0.5
 2.2
1.7
 0.9
 0.8
 3.0
 1.5
 1.5
Segment earnings (loss)$(1.7) $(0.3) $(1.4) $(4.4) $(0.7) $(3.7)$(3.7) $(1.4) $(2.3) $(5.8) $(2.7) $(3.1)

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. The change in depreciation expense primarily relates to increased depreciation rates and additions

to 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.


Operating Results – Three months ended SeptemberJune 30, 20172018 compared to 20162017
 
The following tables summarize the primary drivers for changes in other income (deductions), interest charges, and income taxes:
   
Three Months Ended
September 30, 2017
   Change
Other income (deductions): (In millions)
   
 Decrease in interest income on the Westmoreland Loan (Note 11) $(1.3)
 Other (0.3)
 Net Change $(1.6)
   Three Months Ended
June 30, 2018
   Change
Other income (deductions): (In millions)
   
 Decrease in interest income on the Westmoreland Loan $(1.1)
 Donations (0.5)
 Equity in net earnings of NMRD 0.2
 Net Change $(1.4)
Interest charges:  
   
 Issuance of the $100.0 million 2016 Two-Year Term Loan in December 2016 $(0.6)
 Issuance of the $100.0 million 2016 One-Year Term Loan in December 2016 (0.5)
 Higher short term borrowings and interest rates (0.8)
 Repayment of a $150.0 million PNMR term loan in December 2016 0.5
 Decrease in interest expense on the BTMU Loan Agreement (Note 9) 0.4
 Other (0.1)
 Net Change $(1.1)
Interest charges:  
   
 Repayment of $150.0 million PNMR 2015 Term Loan Agreement in March 2018 $0.8
 Issuance of $300.0 million of PNMR 2018 SUNs in March 2018 (Note 9) (2.4)
 Increase in interest expense on the BTMU Term Loan Agreement (0.2)
 Increase in interest expense on the PNMR 2016 Two-Year Term Loan (0.2)
 Elimination of intercompany interest (Note 9) 0.7
 Other (0.3)
 Net Change $(1.6)

Income taxes:  
   
 Increase in benefit due to change in segment earnings (loss) before income taxes $1.0
 Other 0.1
 Net Change $1.1
   Three Months Ended
June 30, 2018
   Change
Income taxes: (In millions)
   
 Decrease due to reduction in corporate income tax rate and larger segment loss before income taxes $0.5
 Impact of difference in effective tax rates used by PNMR and its subsidiaries in the calculation of income taxes in interim periods 0.3
 Net Change $0.8

Operating Results – NineSix months ended SeptemberJune 30, 20172018 compared to 20162017
 
The following tables summarize the primary drivers for changes in other income (deductions), interest charges, and income taxes:
   
Nine Months Ended
September 30, 2017
   Change
Other income (deductions): (In millions)
   
 Decrease in interest income on the Westmoreland Loan (Note 11) $(3.0)
 2016 interest income from IRS, net of related expenses (Note 13) (0.8)
 2016 costs paid by PNMR Development related to obligations under the SJGS restructuring agreement 0.6
 Other (0.2)
 Net Change $(3.4)

   Six Months Ended
June 30, 2018
   Change
Other income (deductions): (In millions)
   
 Decrease in interest income on the Westmoreland Loan $(1.5)
 Donations (0.5)
 Equity in net earnings of NMRD 0.3
 Other 0.3
 Net Change $(1.4)
   Nine Months Ended
September 30, 2017
   Change
Interest charges: (In millions)
   
 Issuance of the $100.0 million 2016 Two-Year Term Loan in December 2016 $(1.5)
 Issuance of the $100.0 million 2016 One-Year Term Loan in December 2016 (1.4)
 Higher short term borrowings and interest rates (1.9)
 Repayment of a $150.0 million PNMR term loan in December 2016 1.5
 Decrease in interest expense on the BTMU Loan Agreement (Note 9) 0.8
 Other (0.1)
 Net Change $(2.6)
Interest charges:  
   
 Repayment of $150.0 million PNMR 2015 Term Loan Agreement in March 2018 $0.9
 Higher short-term borrowings and interest rates (0.8)
 Issuance of $300.0 million of PNMR 2018 SUNs in March 2018 (Note 9) (3.3)
 Increase in interest expense on the PNMR 2016 Two-Year Term Loan (0.3)
 Elimination of intercompany interest (Note 9) 0.7
 Net Change $(2.8)
Income taxes:  
   
 Increase in benefit due to change in segment (earnings) loss before income taxes $2.3
 Impacts of phased-in reduction in New Mexico corporate income tax rates (0.2)
 Other 0.1
 Net Change $2.2
Income taxes:  
   
 Decrease due to reduction in corporate income tax rate and larger segment loss before income taxes $0.6
 Impact of phased-in reduction in New Mexico corporate income tax rates 0.1
 Impact of difference in effective tax rates used by PNMR and its subsidiaries in the calculation of income taxes in interim periods 1.0
 Other (0.2)
 Net Change $1.5


LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR’s cash flows for the ninesix months ended SeptemberJune 30, 20172018 compared to SeptemberJune 30, 20162017 are summarized as follows:
Nine Months Ended September 30,Six Months Ended June 30,
2017 2016 Change2018 2017 Change
(In millions)(In millions)
Net cash flows from:          
Operating activities$417.3
 $321.0
 $96.3
$133.9
 $200.6
 $(66.7)
Investing activities(329.0) (604.8) 275.8
(200.3) (213.4) 13.1
Financing activities(49.7) 245.4
 (295.1)67.3
 9.4
 57.9
Net change in cash and cash equivalents$38.6
 $(38.4) $77.0
$0.9
 $(3.3) $4.2

Cash Flows from Operating Activities
Changes in PNMR’s cash flow from operating activities result from net earnings, adjusted for items impacting earnings that do not provide or use cash. See Results of Operations above. Certain changes in assets and liabilities resulting from normal operations, including the effects of the seasonal nature of the Company’s operations, also impact operating cash flows.    
Cash Flows from Investing Activities
The changes in PNMR’s cash flows from investing activities relate primarily to changes in utility plant additions. Cash flows from investing activities also include purchases and sales of investment securities in the NDT and coal mine reclamation trusts, including activity to rebalance the investment portfolio. In addition, cash flows from investing activities include activity related to the Westmoreland Loan.Loan and NMRD. Major components of PNMR’s cash inflows and (outflows) from investing activities are shown below:

Nine Months Ended
September 30,
Six Months Ended June 30,
2017 2016 Change2018 2017 Change
Cash (Outflows) for Utility Plant Additions(In millions)(In millions)
PNM:          
Generation$(36.6) $(67.8) $31.2
$(35.8) $(19.8) $(16.0)
Transmission and distribution(124.6) (89.4) (35.2)(63.7) (75.1) 11.4
Purchase of previously leased capacity in PVNGS Unit 2—
 (163.3) 163.3
Four Corners SCRs(24.7) (33.1) 8.4
(6.9) (17.1) 10.2
Nuclear fuel(20.6) (24.1) 3.5
(13.9) (13.7) (0.2)
(206.5) (377.7) 171.2
     (120.3) (125.7) 5.4
TNMP:          
Transmission(54.7) (42.3) (12.4)(51.2) (44.5) (6.7)
Distribution(51.1) (41.5) (9.6)(64.2) (33.3) (30.9)
AMS(1.1) (9.2) 8.1
—
 (1.1) 1.1
(106.9) (93.0) (13.9)(115.4) (78.9) (36.5)
     
Corporate and Other:          
Computer hardware and software(25.3) (31.7) 6.4
(9.9) (20.9) 11.0
PNMR Development utility plant additions(14.7) (0.1) (14.6)—
 (5.4) 5.4
(40.0) (31.8) (8.2)(9.9) (26.3) 16.4
$(353.4) $(502.5) $149.1
$(245.6) $(230.9) $(14.7)
Cash Inflows (Outflows) Related to Investment Securities     
Proceeds from sales of investment securities$794.1
 $358.0
 $436.1
Purchases of investment securities(797.3) (359.9) (437.4)
     $(3.2) $(1.9) $(1.3)
Cash Inflows (Outflows) on the Westmoreland Loan     
Loan origination$—
 $(122.3) $122.3
Cash Inflows on the Westmoreland Loan     
Principal payments28.8
 15.0
 13.8
$56.6
 $19.2
 $37.4
$28.8
 $(107.3) $136.1
Cash Inflows (Outflows) Related to NMRD     
Investments in NMRD$(8.0) $—
 $(8.0)

Cash Flow from Financing Activities
The changes in PNMR’s cash flows from financing activities include:
Short-term borrowings decreased $20.6$22.8 million in 20172018 compared to an increase of $105.3$86.4 million in 2016,2017, resulting in a net decrease in cash flows from financing activities of $125.9$109.2 million
In 2018, PNMR issued $300.0 million aggregate principal amount of 3.250% SUNs and used the proceeds to repay the $150.0 million PNMR 2015 Term Loan Agreement and to reduce short-term borrowings
NM Capital made principal payments on the BTMU Term Loan Agreement of $50.1 million in 2018 compared to $20.4 million in 2017
In 2018, PNM issued $350.0 million of SUNs and repaid $350.0 million of 7.95% of SUNs
In 2018, TNMP issued $60.0 million of 3.85% first mortgage bonds and used the proceeds to reduce short-term debt
In 2017, PNM successfully remarketed $57.0 million of outstanding PCRBs in 2017 and $146.0 million of PCRBs in 2016
In 2016, PNM borrowed $175.0 million under the PNM 2016 Term Loan Agreement utilizing the proceeds to prepay a $125.0 million term loan; in 2017, PNM borrowed $200.0 million under the PNM 2017 Term Loan Agreement utilizing the proceeds to repay the $175.0 million PNM 2016 Term Loan Agreement
TNMP issued $60.0 million of 3.22% first mortgage bonds in 2017 and $60.0 million of 3.53% first mortgage bonds in 2016 utilizing the proceeds to reduce short-term debt and intercompany debt and for general corporate purposes
NM Capital borrowed $122.5 million under the BTMU Term Loan Agreement in 2016 and used the proceeds to provide funds for the Westmoreland Loan; in accordance with the BTMU Term Loan Agreement, NM Capital made principal payments of $31.3 million in 2017 compared to $17.2 million in 2016

Financing Activities

See Note 6 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K and Note 9 for additional information concerning the Company’s financing activities. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. The Company’s ability to access the credit and capital markets at a reasonable cost is largely dependent upon its:
Ability to earn a fair return on equity
Results of operations
Ability to obtain required regulatory approvals

Conditions in the financial markets

Credit ratings

Each of the Company’s revolving credit facilities and term loans contains onehas contained a single financial covenant, which requires the maintenance of debt-to-capitaldebt-to-capitalization ratios of less than or equal to 65%, and generally includesinclude customary covenants, events of default, cross default provisions, and change of control provisions. The Company is in compliance with its debt covenants. In July 2018, the PNMR Revolving Credit Facility, the PNMR 2016 One-Year Term Loan (as extended), the PNMR 2016 Two-Year Term Loan, and the PNMR Development Revolving Credit Facility were each amended such that PNMR is now required to maintain a debt-to-capitalization ratio of less than or equal to 70%. The debt-to-capitalization ratio requirement remains at less than or equal to 65% for PNM and TNMP agreements.

As discussed in Note 11, NM Capital, a wholly-owned subsidiary of PNMR, entered into the $125.0 million BTMU Term Loan Agreement among NM Capital, The Bank of Tokyo-Mitsubishi UFJ, Ltd. (“BTMU”),with BTMU, as lender and BTMU, as Administrative Agent.administrative agent. The BTMU Term Loan Agreement hashad a maturity date of February 1, 2021 and bearsbore interest at a rate based on LIBOR plus a customary spread, which aggregated 4.06% at September 30, 2017. The principal balance outstanding under the BTMU Term Loan Agreement was $60.9 million at September 30, 2017.spread. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding for the $125.0 million Westmoreland Loan to a ring-fenced, bankruptcy-remote, special-purpose entity which is a subsidiary of Westmoreland Coal Company to finance Westmoreland’s purchase of SJCC. On May 22, 2018, the full principal outstanding under the Westmoreland Loan of $50.1 million was repaid. NM Capital used a portion of the proceeds to repay all remaining principal of $43.1 million owed under the BTMU Term Loan Agreement. These payments effectively terminated the loan agreements. In addition, PNMR’s guarantee of NM Capital’s obligations was also effectively terminated. See Note 6.

On October 21, 2016, PNMR entered into letter of credit arrangements with JPMorgan Chase Bank, N.A. (the “JPM LOC Facility”) under which letters of credit aggregating $30.3 million were issued to facilitate the posting of reclamation bonds, which SJCC is required to post in connection with permits relating to the operation of the San Juan mine (Note 11).

At December 31, 2016, PNM had $37.0 million of outstanding PCRBs, which have a final maturity of June 1, 2040, and $20.0 million of outstanding PCRBs which have a final maturity of June 1, 2042. These PCRBs were subject to mandatory tender for remarketing on June 1, 2017 and were successfully remarketed on that date. Both series are now subject to mandatory tender for remarketing on June 1, 2022.

On June 14, 2017, TNMP entered into an agreement, which provided that TNMP would issue $60.0 million aggregate principal amount of 3.22% first mortgage bonds on or about August 25, 2017. TNMP issued the 2017 Series A Bonds on August 24, 2017 and used the proceeds to reduce short-term and intercompany debt and for general corporate purposes.

On July 20, 2017, PNM entered into a $200.0 million term loan agreement (the “PNM 2017 Term Loan Agreement”), which bears interest at a variable rate and must be repaid on or before January 18, 2019. PNM used the proceeds of the PNM 2017 Term Loan Agreement to prepay the $175.0 million PNM 2016 Term Loan Agreement, which was to mature on November 17, 2017, and to reduce short-term borrowings.

On July 28, 2017, PNM entered into the PNM 2017 Senior Unsecured Note Agreement with institutional investors for the sale of $450.0 million aggregate principal amount of eight series of Senior Unsecured NotesSUNs (the “PNM 2018 SUNs”) offered in private placement transactions. In May 2018, PNM has agreed to issueissued $350.0 million of the PNM 2018 SUNs (at fixed annual interest rates ranging from 3.15% to 4.50% for terms between 5 and 30 years) and used the proceeds to repay an equal amount of PNM’s 7.95% SUNs that matured on or about May 15, 2018 and2018. PNM issued the remaining $100.0 million of the PNM 2018 SUNs (at fixed annual interest rates of 3.78% and 4.60% for terms of 10 and 30 years) on or about August 1, 2018. The issuances of the PNMJuly 31, 2018 SUNs are subject to the satisfaction of customary conditions. PNMand will use the gross proceeds from the PNM 2018 SUNs to pay $350.0 million of PNM’s 7.95% Senior Unsecured Notes that mature on May 15, 2018 and $100.0 millionrepay an equal amount of PNM’s 7.50% Senior Unsecured Notes that matureSUNs at their maturity on August 1, 2018.

On September 25, 2017,March 9, 2018, PNMR issued $300.0 million aggregate principal amount of 3.250% SUNs (the “PNMR 2018 SUNs”), which mature on March 9, 2021. The proceeds from the TNMP Revolving Credit Facility, which has a financing capacity of $75.0 million, was amended and restatedoffering were used to extend its maturity from September 18, 2018 to September 23, 2022.

At September 30, 2017, variable interest rates were 2.14% forrepay the $150.0 million PNMR 2015 Term Loan Agreement 2.09%and to reduce borrowings under the PNMR Revolving Credit Facility.

On February 26, 2018, PNMR Development entered into a $24.5 million revolving credit facility with Wells Fargo Bank, National Association, as lender. The facility allows PNMR Development to borrow on a revolving credit basis and also provides for the $100.0issuance of letters of credit. The facility expires on February 25, 2019. The facility bears interest at a variable rate and contains terms similar to the PNMR Revolving Credit Facility. PNMR has guaranteed the obligations of PNMR Development under the facility. PNMR Development uses the facility to finance its participation in NMRD and other activities.

On June 28, 2018, TNMP entered into an agreement under which TNMP issued $60.0 million PNMR 2016 One-Yearaggregate principal amount of 3.85% first mortgage bonds, due 2028. On July 25, 2018, TNMP entered into the $20.0 million TNMP 2018 Term Loan 2.19%Agreement that bears interest at a variable rate, which was 2.76% at July 25, 2018, and has a maturity of July 25, 2020. TNMP used the proceeds from these issuances to repay short-term borrowings and for general corporate purposes.

At June 30, 2018, variable interest rates were 2.88% for the $100.0 million PNMR 2016 Two-Year Term Loan and 1.97%2.83% for the $200.0 million PNM 2017 Term Loan Agreement.

PNMR has a hedging agreement whereby it effectively established a fixed interest rate of 1.927%, subject to change if there is a change in PNMR’s credit rating, for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018. In 2017, PNMR entered into three separate four-year hedging agreements whereby it effectively established fixed interest rates on three separate tranches, each of $50.0 million, of its variable rate debt. The hedging agreements effectively fix interest rates on the aggregate $150.0 million of short-term debt at rates of 1.926%, 1.823%, and 1.629%, plus customary spreads over LIBOR, and are subject to changes if there is a change in PNMR’s credit rating. The Finance Committee

of the Board has authorized management to enter into additional transactions to hedge against exposure to changes in interest rates on its variable rate debt of up to an additional notional amount of $150.0 million.
Capital Requirements

PNMR’s 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 SeptemberJune 30, 20172018, are:
2017 2018-2021 Total2018 2019-2022 Total
(In millions)(In millions)
Construction expenditures$526.9
 $2,046.1
 $2,573.0
$514.1
 $2,211.2
 $2,725.3
Dividends on PNMR common stock77.3
 309.0
 386.3
84.4
 337.7
 422.1
Dividends on PNM preferred stock0.5
 2.1
 2.6
0.5
 2.1
 2.6
Total capital requirements$604.7
 $2,357.2
 $2,961.9
$599.0
 $2,551.0
 $3,150.0
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 environmental upgrades of $42.9$8.4 million at Four Corners, $44.3$71.6 million for 30 MW of new solar capacity to supply power to a new data center being constructed by Facebook Inc., $72.8 million related to PNM’s request for NMPRC approval to procure 50 MW of new solar facilities included in PNM’s 2018 renewable energy procurement plan, approximately $200$170 million in 2018-2020 for an anticipated expansion of PNM’s transmission system, and approximately $100 million in 2021 and $300 million in 2022 for the initial costs of replacement resources related to the potential shutdown of SJGS Units 1 and 4 in 2022. See Note 12.Expenditures for the expansion of PNM’s transmission system and SJGS replacement resources are subject to obtaining necessary approvals of the NMPRC. PNM will be required to file CCN applications with the NMPRC to obtain those approvals, as well as to make an abandonment filing for approval to shut down SJGS. Expenditures for environmental upgrades are estimated to be $35.0$8.4 million in 2017, including amounts expended through September 30, 2017. See Note 11 and Commitments and Contractual Obligations below.2018. 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 20162017 Annual Reports on Form 10-K describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP.
During the ninesix months ended SeptemberJune 30, 20172018, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements and the borrowings discussed in Financing Activities above.
 
In addition to the capital requirements for construction expenditures and dividends, the Company has long-term debt and term loans that must be paid or refinanced at maturity. The $100.0 million PNMR 2016 One-Year Term Loan (as extended) matures on December 14, 2018, the $100.0 million PNMR 2016 Two-Year Term Loan matures on December 21, 2018, the $200.0 million PNM 2017 Term Loan matures on January 18, 2019, and $172.3 million of TNMP first mortgage bonds are due in April 2019. Also, the $150.0$24.5 million PNMR 2015 Term Loan Agreement matures on March 9, 2018, $350.0 million of PNM Senior Unsecured Notes mature on May 15, 2018, andDevelopment Revolving Credit Facility expires in February 2019. In addition, $100.0 million of PNM Senior Unsecured NotesSUNs mature on August 1, 2018. AsHowever, as described above, PNM entered into the PNM 2017 Senior Unsecured Note Agreement on July 28, 2017. Proceeds from the $450.02017 under which PNM issued $100.0 million of the PNM 2018 SUNs to be issued under that agreement will be usedon July 31, 2018 to repay the Senior Unsecured Notes that maturean equal amount of SUNs at their maturity on May 15, 2018 and August 1, 2018. The BTMU Term Loan Agreement requires that NM Capital utilize all amounts, less taxes and fees, it receives under the Westmoreland Loan to repay the BTMU Term Loan Agreement. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $15.7 million on the BTMU Term Loan Agreement in the twelve months ended September 30, 2018. The Company has additional long-term debt of $102.3 million that matures from October 2018 through December 2018. Note 6 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K contains additional information about the maturities of long-term debt. PNMR and PNM anticipate that funds to repay these long-term debt maturities and term loans will come from entering into new arrangements similar to the existing agreements, borrowing under their revolving credit facilities, issuance of new long-term debt in the public or private capital markets, 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 or make additional debt repurchases in the future.

Liquidity
PNMR’s liquidity arrangements include the PNMR Revolving Credit Facility, the PNM Revolving Credit Facility, and the TNMP Revolving Credit Facility. In July 2018, the PNMR Revolving Credit Facility was amended to provide for two one-year extension options, subject to approval by a majority of the lenders. The PNMR and PNM facilities have capacities of $300.0 million and $400.0 million through October 2020 and $290.0 million and $360.0 million from November 2020 through October 2021.2022. The $75.0 million TNMP Revolving Credit Facility matures onin September 23, 2022. PNM also has the $50.0$40.0 million PNM 2017 New Mexico Credit Facility, which expires in January 2018.December 2022. PNMR Development has a $24.5 million revolving credit

facility that expires in February 2019. The Company believes the terms and conditions of these facilities are consistent with those of other investment grade revolving credit facilities in the utility industry.  The Company expects that it will be able to extend or replace these credit facilities under similar terms and conditions prior to their expirations.
The revolving credit facilities and the PNM 2017 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. Information regarding the range of borrowings for each facility is as follows:
 Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
Range of Borrowings Low High Low High Low High Low High
 (In millions) (In millions)
PNM:                
PNM Revolving Credit Facility $—
 $40.1
 $—
 $65.0
 $—
 $40.0
 $—
 $64.2
PNM New Mexico Credit Facility —
 10.0
 —
 26.0
PNM 2017 New Mexico Credit Facility —
 10.0
 —
 20.0
TNMP Revolving Credit Facility —
 52.0
 —
 53.0
 10.1
 73.9
 —
 73.9
PNMR Revolving Credit Facility 159.2
 235.3
 111.8
 235.3
 92.7
 122.6
 29.1
 210.0
PNMR Development Revolving Credit Facility 21.5
 24.5
 —
 24.5
At SeptemberJune 30, 2017,2018, the average interest rate was 2.49%3.33% for the PNMR Revolving Credit Facility. There were no borrowings underFacility, 2.89% for the PNMR 2016 One-Year Term Loan (as extended), 3.22% for the PNM Revolving Credit Facility, 3.22% for the PNM 2017 New Mexico Credit Facility, or2.84% for the TNMP Revolving Credit Facility, at September 30, 2017.and 3.05% for the PNMR Development Revolving Credit Facility.
The Company currently believes that its capital requirements for at least the next twelve months can be met through internal cash generation, existing, extended, or new credit arrangements, and access to public and private capital markets. However, theThe Company anticipates that it will be necessary to obtain additional long-term financing to fund its capital requirements during the 2017-20212018-2022 period. This could include new debt issuances and/or equity issuances. The Company currently anticipates utilizing a three-year at-the-market equity issuance program to raise equity beginning in 2020 to partially fund capital requirements. This at-the-market program should provide a flexible, efficient, and low-cost way to issue equity as needed. The Company also expects to issue new equity.debt periodically to fund capital investments. 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 2008 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.
Information concerning the credit ratings for PNMR, PNM, and TNMP was set forth under the heading Liquidity in the MD&A contained in the 20162017 Annual Reports on Form 10-K. As of October 20, 2017July 25, 2018, ratings on the Company’s securities were as follows:


 PNMR PNM TNMP
S&P     
Corporate ratingBBB+ BBB+ BBB+
Senior secured debt* * A
Senior unsecured debt*BBB BBB+ *
Preferred stock* BBB- *
Moody’s     
Issuer ratingBaa3 Baa2 A3
Senior secured debt* * A1
Senior unsecured debt*Baa3 Baa2 *
* Not applicable     

Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade. On January 16, 2018, S&P haschanged the outlook for PNMR, PNM, and TNMP on afrom stable outlook. Into negative while affirming the ratings above for all entities. On June 2017,29, 2018, Moody’s changed the ratings outlook for PNMR and PNM from positive to stable, to positive while maintaining amaintained the stable outlook for TNMP. However,TNMP, and affirmed the long-term credit ratings of each entity. The ultimate outcomeoutcomes from PNM’s NM 2015 Rate Case and NM 2016 Rate Case, including the pending appealappeals before the NM Supreme Court, and the outcome of PNM’s NM 2016TNMP 2018 Rate Case, as discussed in Note 12, 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 each rating 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 20, 2017July 25, 2018 is as follows:
PNMR
Separate
 
PNM
Separate
 
TNMP
Separate
 
PNMR
Consolidated
PNM TNMP 
PNMR
Separate
 
PNMR
Development
 PNMR Consolidated
(In millions)(In millions)
Financing capacity:                
Revolving credit facility$300.0
 $400.0
 $75.0
 $775.0
$400.0
 $75.0
 $300.0
 $24.5
 $799.5
PNM New Mexico Credit Facility—
 50.0
 —
 50.0
PNM 2017 New Mexico Credit Facility40.0
 —
 —
 —
 40.0
Total financing capacity$300.0
 $450.0
 $75.0
 $825.0
$440.0
 $75.0
 $300.0
 $24.5
 $839.5
                
       
Amounts outstanding as of October 20, 2017:       
Amounts outstanding as of July 25, 2018:         
Revolving credit facility$175.1
 $—
 $5.9
 $181.0
$8.8
 $6.2
 $111.0
 $24.5
 $150.5
PNM New Mexico Credit Facility—
 —
 —
 —
10.0
 —
 —
 —
 10.0
Letters of credit6.4
 2.5
 0.1
 9.0
2.5
 0.1
 6.5
 —
 9.1
       
Total short-term debt and letters of credit181.5
 2.5
 6.0
 190.0
21.3
 6.3
 117.5
 24.5
 169.6
                
Remaining availability as of October 20, 2017$118.5
 $447.5
 $69.0
 $635.0
Invested cash as of October 20, 2017$1.5
 $50.5
 $—
 $52.0
Remaining availability as of July 25, 2018$418.7
 $68.7
 $182.5
 $—
 $669.9
Invested cash as of July 25, 2018$—
 $—
 $0.9
 $—
 $0.9
In addition to the above, PNMR had $30.3 million of letters of credit outstanding under the JPM LOC Facility. The above table excludes intercompany debt. As of October 20, 2017,July 25, 2018, PNM and TNMP had no intercompany borrowings from PNMR.PNMR of $20.0 million and $3.5 million. The remaining availability under the revolving credit facilities at any point in time varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures.

For offerings of debt or equity securities registered with the SEC, PNMR has a shelf registration statement expiring in March 2021. This shelf registration statement has unlimited availability and can be amended to include additional securities, subject to certain restrictions and limitations. PNMR can also offer new shares of common stock through the PNM Resources Direct Plan under a SEC shelf registration statement that expires in August 2018. PNM has a shelf registration statement for up to $475.0 million of Senior Unsecured NotesSUNs that expires in May 2020.
Off-Balance Sheet Arrangements
PNMR’s off-balance sheet arrangements include PNM’s operating leases for portions of PVNGS Units 1 and 2. These arrangements help ensure PNM the availability of lower-cost generation needed to serve customers. See MD&A – Off-Balance

Sheet Arrangements and Notes 7 and 9 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K, as well as Note 6.

13.
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 20162017 Annual Reports on Form 10-K.

Contingent Provisions of Certain Obligations
As discussed in the 20162017 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,
2017		 December 31,
2016		June 30,
2018		 December 31,
2017
PNMR      
PNMR common equity41.8% 41.1%39.8% 40.9%
Preferred stock of subsidiary0.3% 0.3%0.3% 0.3%
Long-term debt57.9% 58.6%59.9% 58.8%
Total capitalization100.0% 100.0%100.0% 100.0%
      
PNM      
PNM common equity47.5% 46.0%46.6% 46.0%
Preferred stock0.4% 0.4%0.4% 0.4%
Long-term debt52.1% 53.6%53.0% 53.6%
Total capitalization100.0% 100.0%100.0% 100.0%
      
TNMP      
Common equity55.4% 58.5%54.6% 56.9%
Long-term debt44.6% 41.5%45.4% 43.1%
Total capitalization100.0% 100.0%100.0% 100.0%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background
In 2016, GHG associated with PNM’s interests in its fossil-fueled generating plants included approximately 6.6 million metric tons of CO2, which comprises the vast majority of PNM’s GHG.  By comparison, the total GHG in the United States in 2015, the latest year for which EPA has published this data, were approximately 6.6 billion metric tons, of which approximately 5.4 billion metric tons were CO2. 
PNM has several programs underway to reduce or offset GHG from its resource portfolio, thereby reducing its exposure to climate change regulation. See Note 12. PNM owns utility-scale solar generation with a total generation capacity of 107 MW. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and, si

nce January 2015, has purchased the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW. PNM has a 20-year PPA for the output of Lightning Dock Geothermal, which began providing power to PNM in January 2014. The current capacity of the geothermal facility is 4 MW. On June 1, 2017, PNM filed its 2018 renewable energy procurement plan (Note 12). PNM is requesting approval to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; approval to procure an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; and approval to procure 50 MW of new solar facilities to be constructed beginning in 2018. Additionally, PNM has a customer distributed solar generation program that represented 81.6 MW at September 30, 2017. PNM’s distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 180 GWh. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a budget of $26.0 million for the 2017 program year. These programs saved approximately 82 GWh of electricity in 2016. Over the next 20 years, PNM projects energy efficiency and load management programs will provide the equivalent of approximately 9,600 GWh of electricity, which will avoid at least 5.2 million metric tons of CO2 based upon projected emissions from PNM’s system-wide resources. These estimates are subject to change because of the uncertainty of many of the underlying variables, including changes in demand for electricity, and complex relationships between those variables.

For the past several years, management has identified multiple risks and opportunities related to climate change, including potential environmental regulation, technological innovation, and availability of fuel and water for operations, as among the most significant risks facing the Company. Accordingly, these risks are overseen by the full Board in order to facilitate more integrated risk and strategy oversight and planning. Board oversight includes understanding the various challenges and opportunities presented by these risks, including the financial consequences that might result from potential federal and/or state regulation of GHG; plans to mitigate the risks; and the impacts these risks may have on the Company’s strategy. In addition, the Board approves certain PNM investments in environmental equipment and grid modernization technologies.

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.  Management has recently published, with Board oversight, a Climate Change Report available at http://www.pnmresources.com/about-us/sustainability-portal.aspx, that details PNM’s efforts to transition to a coal-free generation portfolio. The Board considers issues associated issues aroundwith climate change, the Company’s GHG exposures, and the financial consequences that might result from potential federal and/or state regulation of GHG.

Changes in the climate are generally not expected to have material consequences to the Company in the near-term. The Company cannot anticipate or predict the potential long-term effects of climate change or climate change related regulation on its assets and operations.

Greenhouse Gas Emissions (“GHG”) Exposures

In 2017, GHG associated with PNM’s interests in its fossil-fueled generating plants included approximately 6.9 million metric tons of CO2, which comprises the vast majority of PNM’s GHG.  By comparison, the total GHG in the United States in 2016, the latest year for which EPA has published final data, were approximately 6.5 billion metric tons (in CO2 equivalents), of which approximately 5.3 billion metric tons were CO2.

As of December 31, 2016,January 1, 2018, approximately 70.7%67.9% 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,This reflects the Company expects itsretirement of SJGS Units 2 and 3 that occurred in December 2017 and the restructuring of ownership in SJGS Unit 4. These events reduced PNM’s entitlement in SJGS from 783 MW to 562 MW and will cause the Company’s output of GHG from existing sources willto decrease in the near-term.2018 compared to 2017. Many factors affect the amount of GHG emitted, including plant performance, economic dispatch, and the availability of renewable resources. For example, between 2007 and 2016,2017, production from New Mexico Wind has varied from a high of 580 GWh in 2011 to a low of 405 GWh in 2014. Variations are primarily due to how much and how often the wind blows. In addition, if PVNGS experienced prolonged outages or if PNM’s entitlement from PVNGS were reduced, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG.

PNM has several programs underway to reduce or offset GHG from its generation resource portfolio, thereby reducing its exposure to climate change regulation. See Note 12. As described in Note 11, PNM received approval for the December 31, 2017 shutdown of SJGS Units 2 and 3 as part of its strategy to address the regional haze requirements of the CAA. Based on 2016 data, theThe shutdown of SJGS Units 2 and 3 wouldis expected to result in a reduction of GHG for the entire station of approximately 50%, including an overall reduction of approximately 40% of GHG from the Company’s owned interests. In addition, as discussed in Note 12, PNM’s 2017 IRP indicates exiting ownership in the remaining SJGS units in 2022 and Four Corners in 2031 would provide long-term cost savings to its customers and would further reduce PNM’s GHG. PNM owns utility-scale solar generation with a total generation capacity of 107 MW. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and, since January 2015, has purchased the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW. PNM has a 20-year PPA for the output of Lightning Dock Geothermal, which began providing power to PNM in January 2014. The current capacity of the geothermal facility is 4 MW. On November 15, 2017 the NMPRC approved PNM’s 2018 renewable energy procurement plan. As a result, PNM will acquire an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothe

rmal; and PNM will construct 50 MW of new solar facilities in 2018 and 2019. Additionally, PNM began purchasing renewable energy from 30 MW of solar PV facilities owned by NMRD in 2018 to provide energy to a new data center being constructed in PNM’s service territory (Note 11). PNM also has a customer distributed solar generation program that represented 91.9 MW at June 30, 2018. PNM’s distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 200 GWh. PNM has offered its customers a comprehensive portfolio of energy efficiency and load management programs since 2007, with a budget of $23.6 million for the 2018 program year. PNM’s cumulative annual savings from these programs were approximately 622 GWh of electricity in 2017. Over the next 20 years, PNM projects energy efficiency and load management programs will provide the equivalent of approximately 8,000 GWh of electricity, which will avoid at least 4.3 million metric tons of CO2 based upon projected emissions from PNM’s system-wide resources. These estimates are subject to change because of the uncertainty of many of the underlying variables, including changes in demand for electricity, and complex relationships between those variables.

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.

Other Climate Change Risks

PNM’s generating stations are located in the arid southwest. Access to water for cooling for some of these facilities is critical to continued operations. Forecasts for the impacts of climate change on water supply in the southwest range from reduced precipitation to changes in the timing of precipitation. In either case, PNM’s generating facilities requiring water for cooling will need to mitigate the impacts of climate change through adaptive measures. Current measures employed by PNM generating stations such as air cooling, use of grey water, improved reservoir operations, and shortage sharing arrangements with other water users will continue to be important to sustain operations.

PNM’s service areas occasionally 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 Company-owned facilities, which disrupts the ability to transmit and/or distribute energy, weather and other events of nature can temporarily reduce customers’ usage and demand for energy. During the third quarter of 2017, HurricanesHurricane Harvey and Irma had significant impacts on the Gulf Coast region, including certain areas serviced by TNMP. While neither hurricane hadHurricane Harvey did not have a significant impact on TNMP’s facilities, the hurricaneshurricane impacted customer usage and could impact future usage or create resource constraints that could delay or disrupt the supply of materials necessary to maintain historical levels of system reliability.
Changes in the climate are generally not expected to have material consequences to the Company in the near-term. The Company cannot anticipate or predict the potential long-term effects of climate change or climate change related regulation on its assets and operations.

EPA Regulation

In April 2007, the US 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 for emissions from new motor vehicles, stating that the atmospheric concentrations of six key greenhouse gases (CO2, methane, nitrous oxides, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride) endanger the public health and welfare of current and future generations. In May 2010, EPA released the final PSD and Title V Greenhouse Gas Tailoring Rule (the “Tailoring Rule”) to address GHG from stationary sources under the CAA permitting programs. The purpose of the rule was to “tailor” the applicability of two programs, the PSD construction permit 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 CO2 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 CO2 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 DC 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 US Supreme Court granted a petition for a Writ of Certiorari regarding the permitting of stationary sources that emit GHG. The US Supreme Court limited its review to the question of 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 was unlawful as it violates Congressional intent.

On June 23, 2014, the US Supreme Court issued its opinion in the above case and reversed the DC Circuit. First, the US 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, the US Supreme Court rejected EPA’s position 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. Third, the US Supreme Court found EPA lacked authority to “tailor” the CAA’s unambiguous numerical thresholds of 100 or 250 tons per year. Fourth,year, and thus held EPA may not require a source to obtain a PSD permit solely on the US Supreme Court found that it would be reasonable for EPAbasis of its potential GHG emissions. However, the court upheld EPA’s authority to interpret the CAA to limitapply the PSD program for GHGs to “anyway” sources – those sources that have to comply with the PSD program for other non-GHG pollutants. The US Supreme Court said that EPA needed to establish a de minimis level below which BACT would not be required for “anyway” sources. In response to the US Supreme Court decision, EPA released a proposed rule on October 3, 2016, to revise the permitting rules for GHG under the CAA. Among other things, the proposed rule would set the Significant Emissions Rate (“SER”) for GHGs under the major source permitting program at 75,000 tons of CO2 equivalent per year for new and modified sources that are already subject to NSR based on emission of other pollutants. If finalized as proposed, the rule would require a new major source or major modification that triggers PSD permitting for other criteria pollutants like NOx to undergo a BACT review for GHG if the potential to emit GHG exceeds the 75,000 tons per year. Comments on the proposed rule were due on December 16, 2016.

On June 25, 2013, formerthen President Obama announced his Climate Action Plan, which outlined how his administration planned 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 proposed actions that would lead to the reduction of GHG by 17% below 2005 levels by 2020. The former President also issued a Presidential Memorandum to EPA to continue development of the GHG NSPS

regulations for electric generators. The Presidential Memorandum established a timeline for the proposal and issuance of a GHG NSPS for new sources under section 111(b) of the CAA 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 directed 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 the standards are developed and implemented in a manner that provides for reliable and affordable energy. The Presidential Memorandum required EPA to undertake the rulemaking through direct engagement with states, “as they will play a central role in establishing and implementing standards for existing power plants,” and with utility leaders, labor leaders, non-governmental organizations, tribal officials, and other stakeholders.

EPA met the former President’s timeline for issuance of carbon pollution standards for new sources under Section 111(b) and for existing sources under Section 111(d) of the CAA. On August 3, 2015, EPA issued its final standardsresponded to limit CO2 emissions from power plants. The final rule was published on October 23, 2015. Threethe Climate Action Plan by issuing three separate but related actions took place:actions: (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.Plan.

EPA’s final ruleCarbon Pollution Standards for new sources (those constructed after January 8, 2014) established separate standards for gas- and coal-fired units. The standards reflect the degree of emission limitation achievable through the application of what EPA determined to limit GHG from new, modified, and reconstructed power plants establishes standards based upon certain, specific conditions.be the best system of emission reduction (“BSER”) demonstrated for each type of unit. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, EPA finalized a standard of 1,000 lbs CO2/MWh-gross based on efficient natural gas combined cycled technology as the best system of emissions reductions (“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 lbs CO2/MWh-net. A new source is any newly constructed fossil fuel-fired power plant that commenced construction after January 8, 2014.

cycle technology. 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 are required to meet an emissions standard equal to 1,400 lbs CO2/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 CO2 per MWh, which will apply to units with modifications resulting in an increase of hourly CO2 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 an emission limit of 1,800 lbs CO2/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 CO2/MWh-gross.

The final Clean Power Plan rule changed significantly in structure from the proposed rule that was released in June 2014. 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 twoestablished numeric “emission standards” for existing electric generating units – 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 lbs/MWh for fossil-steam units and 771 lbs/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, the Clean Power Plan compliance schedule required states to make initial plan submissions to EPA by September 6, 2016. EPA could then choose to grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension were to submit an update to EPA in 2017 and final plans by September 2018. States not requesting an extension were to submit their final plans by September 2016. 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 (“CEIP”) 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. On June 30, 2016, EPA published proposed design details of the CEIP. Comments were due to EPA on November 1, 2016. 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 CO2 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 indicated that states may voluntarily adopt the Federal Plan in whole or in part as its state plan. EPA explained 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 an 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 indicated that it will choose only one of these approaches in the final Federal Plan. However, the proposed rule offered both approaches for states to use as models in their own plans. EPA asked for comments on the proposed Federal Plan by January 21, 2016. PNM submitted comments in response.

Multiple states, utilities, and trade groups filed petitions for review and motions to stay in the DC Circuit. On January 21, 2016,Circuit to challenge both the DC Circuit denied the motions to stay the EPA’s section 111(d) rule (the Clean Power Plan). It did, however, expedite briefing in the caseCarbon Pollution Standards for new sources and set it for oral argument on June 2, 2016. Under the court’s order, briefing on all issues was to be completed by April 22, 2016. Petitioners had asked for bifurcated briefing that would allow the core legal issues to be litigated first and the programmatic issues related to the rule to be litigated later depending on the outcome of the litigation. The court denied that request.

On January 26, 2016, 29 states and state agencies filed a petition to the US Supreme Court asking the court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court granted the applicationsPlan for existing sources. Numerous parties also simultaneously filed motions to stay the Clean Power Plan pending judicial review ofduring the rule.litigation. The US Supreme Court issued a one-page order that stated, “The EPADC Circuit refused to stay the rule, to havebut 29 states cut power sector carbon dioxide (CO2) emissions 32% by 2030 is stayed pending disposition of the applicants’ petitions for review in the United States Court of Appeals for the District of Columbia Circuit.” The vote was 5-4 amongand state agencies successfully petitioned the US Supreme Court Justices. The decision meansfor a stay, which was granted on February 9, 2016. As a result, the Clean Power Plan is not in effect and neither states nor sources are not obliged to comply with its requirements. TheWith the US Supreme Court stay in place, the DC Circuit heard oral arguments on the merits of the states’ caseClean Power Plan on September 27, 2016. The arguments were made2016 in front of a 10-judge en bancpanel. There is no mandatory deadline forHowever, before the DC Circuit could issue an opinion, President Trump took office and his administration asked the court to make a decision onhold the case. The stay will remaincase in effect pending US Supreme Court review if such reviewabeyance while the rule is sought.re-evaluated, which the court granted.

On March 28, 2017, President Trump issued an Executive Order titled “Promoting Energy Independence and Economic Growth.” Among its goals are to “promote clean and safe development of our Nation’s vast energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation.” The order rescinds several key pieces of the Obama Administration’s climate agenda, including the Climate Action Plan and the Final Guidance on Consideration of Climate Change in NEPA Reviews. It directs agencies to review and suspend, revise or rescind any regulations or agency actions that potentially burden the development or use of domestically produced energy resources.

Most notably, the order directs EPA to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the NSPSCarbon Pollution Standards for GHG from new, reconstructed or modified electric utilities, (2) the Clean Power Plan, (3) the Proposed Clean Power Plan Model Trading Rules, and (4) the Legal Memorandum supporting the Clean Power Plan, and (5)Plan. In response, the NSPS for Oil & Natural Gas Sector. The Order disbands the Interagency Working Group on the Social Cost of Greenhouse Gases, rescinds all documents developed by that group as “no longer representative of government policy,” and directs agencies to evaluate costs consistent with a 2003 memorandum from the Office of Management and Budget. In addition, the order repeals the moratorium on new leases for coal mined from federal lands. Finally, it requires EPA and the Department of Justice to work with the US Attorney General to put on hold any litigation regarding any of the regulations the order addresses. Subsequently, EPA and the Department of Justice filed a motion in the DC Circuit seeking to hold the Clean Power Plan case in abeyance. The DC Circuit granted EPA’s request, has held the litigation in abeyance, and has not yet ruled on the case.


On October 10, 2017, the EPA Administrator signed a NOPR to repeal the Clean Power Plan.Plan on October 10, 2017. The notice proposes a legal interpretation concluding that the Clean Power Plan exceeds EPA’s statutory authority. The NOPR was published in the Federal RegisterEPA accepted comments on October 16, 2017, starting a 60-day public comment period.that proposed interpretation through April 26, 2018. Any final rule will likely be subject to legal challenge and judicial review. On December 18, 2017, EPA indicated it has not determined whether it will promulgatereleased an advanced NOPR addressing GHG guidelines for existing electric utility generating units. Comments were due by February 26, 2018. On July 9, 2018, EPA submitted a newproposed rule under section 111(d) or what form a new rule would take. EPA is evaluating whether it is appropriatetitled “State Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units” to replace the ruleUnited States Office of Management and will seek feedback from the public on crafting a replacement at a later date.Budget for interagency review.

PNM is unable to predict the impact to the Company of this Executive Order orthese proposed rulemakings, including the potential repeal of the Clean Power Plan. It is uncertain the direction EPA will take, if any, to replace the existing rule. If a future regulation limiting GHG from fossil-fueled EGUs is adopted, such regulations wouldcould impact PNM’s existing and future fossil-fueled EGUs. The existing Carbon Pollution Standards covering new sources willcould also impact PNM’s generation fleet, although that rule is alsoremains under review by EPA. Impacts could result in requirements for investments in additional renewables and energy efficiency programs, efficiency improvements, and/or control technologies at PNM’s fossil-fueled EGUs. 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 GHG reduction from coal and gas-fired power plants 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 BART plan at SJGS that required the installation of SNCRs on Units 1 and 4 by early 2016, which has been completed,EPA and the retirement of SJGS Units 2 and 3 by the end of 2017 as described in Note 11, as well as the exiting ownership in the remaining SJGS units in 2022 as discussed in Note 12 should provide a significant step for New Mexico to meet its ultimate compliance with future regulations limiting GHG. PNM is unable to predict the impact on its fossil-fueled generation.DC Circuit.

Federal Legislation

Prospects for enactment in Congress of legislation imposing a new or enhanced regulatory program to address climate change are highly unlikely in 2017.  EPA continues to be the primary vehicle for GHG regulation in the near future, especially for coal-fired EGUs.2018.  


State and Regional Activity

Pursuant to New Mexico law, each utility must submit an IRP to the NMPRC every three years to evaluate renewable energy, energy efficiency, load management, distributed generation, and conventional supply-side resources on a consistent and comparable basis.  The IRP is required to take into consideration risk and uncertainty of fuel supply, price volatility, and costs of anticipated environmental regulations when evaluating resource options to meet supply needs of the utility’s customers.  The NMPRC requires that New Mexico utilities factor a standardized cost of carbon emissions into their IRPs using prices ranging between $8 and $40 per metric ton of CO2 emitted and escalating these costs by 2.5% per year.  Under the NMPRC order, each utility must analyze these standardized prices as projected operating costs.  Reflecting the developing nature of this issue, the NMPRC order states that these prices may be changed in the future to account for additional information or changed circumstances.  Although these prices may not reflect the costs that ultimately will be incurred, PNM is required to use these prices for purposes of its IRP.  As discussed in Note 12, in theIn its 2017 IRP, PNM analyzed resource portfolio plans for scenarios that assumed SJGS will operate beyond the end of the current coal supply agreement that runs through June 30, 2022 and for scenarios that assumed SJGS will cease operations by the end of 2022.2022 as discussed in Note 12. The key findings of the 2017 IRP include that exiting SJGS in 2022 would provide long-term cost benefits to PNM’s customers and that PNM exiting its ownership interest in Four Corners in 2031 would also save customers money. The materials presented in the IRP process are available at www.pnm.com\irp.

On August 30, 2017, Western Resource Advocates provided the NMPRC with a presentation on a proposed rulemaking for the adoption of a clean energy standard in New Mexico and a suggestion that the NMPRC issue a NOPR. The NMAG’s office and Prosperity Works joined in the petition. The proposed clean energy standard, if adopted, would require utilities to reduce carbon emissions by four percent per year for the next 20 years. On October 4, 2017, theThe NMPRC votedhas convened a series of workshops to table a draft order that would have provided for workshops for stakeholders to discuss the adoption ofdevelop a clean energy standard in New Mexico. A workshop onrule that could be proposed for a future rulemaking proceeding. The major topic areas discussed at the proposed clean energy standard was held on October 18, 2017 pursuant to an order issued by the NMPRC. A number of issues were discussed and three major areas were identified with designated utilities or others chosen to lead sub-groups who will explore these areas:workshops are: jurisdictional and other legal issues; selection of the timeframe for the emissions baseline year to be used, unspecified power, and electric vehicle credits; and cost responsibilities, benefits, reasonable cost threshold, impact on rates, projected impact on utilities and whether they can comply,compliance issues, reliability impacts, and unintended consequences. A follow-up meeting will be held November 17, 2017Workshops were completed in 2018. PNM is unable to considerpredict the statusoutcome of the sub-group findings.


On August 25, 2017, WEG, on behalf of 28 teens and youths, petitioned the New Mexico Environmental Improvement Board to schedule a hearing to consider and adopt a newany proposed rule for a state Greenhouse Gas Reduction Program to reduce greenhouse gas emissions in the state. The petition and draft rule as written would require creation of a Climate Action Plan within six months, direct NMED to require reductions of “New Mexico’s total in-boundary and embedded CO2 emission at least eight percent per year beginning in 2018,” and mandate NMED to adopt a carbon budget by the end of 2018 to meet the following reduction targets for NM CO2: 10% below 1990 levels by 2020; 68% below 1990 levels by 2030; and 91% below 1990 levels by 2050. The petition was denied.that may result from this process.

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 atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.”  Parties to the UNFCCC, 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 Kyoto Protocol, which was agreed to in 1997 and established legally binding obligations for developed countries to reduce their GHG, 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 to negotiate by 2015 an international agreement involving commitments by all nations to begin reducing carbon emissions by 2020. 

On December 12, 2015, the Paris Agreement was finalized during the 2015 COP. The agreement, which was agreed to by more than 190 nations, requires that countries submit Nationally Determined Contributions (“NDCs”). NDCs reflect national targets and actions that arise out of national policies and elements relating to oversight, guidance and coordination of actions to reduce emissions by all countries. In November 2014, formerthen President Obama announced the United States’ commitment to reduce GHG, on an economy-wide basis, by 26%-28% from 2005 levels by the year 2025. The United States NDC is part of an overall effort by the Obama Administrationformer administration to have the United States achieve economy-wide reductions of around 80% by 2050.  The former administration’s GHG reduction target for the electric utility industry is a key element of its NDC and is based on EPA’s final GHG regulations for new, existing, and modified and reconstructed sources.

The United States was one of 189 nations that offered intended NDCs.  Thresholds for the number of countries necessary to ratify or accede to the Paris Agreement and total global GHG percentage were achieved on October 5, 2016 and the Paris Agreement entered into force on November 4, 2016.  To date, 168178 countries have ratified the Paris Agreement.  On June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement. In his public statement, he indicated that the United States would "begin“begin negotiations to reenter either the Paris Accord or a....newa .... new transaction on terms that are fair to the United States, its businesses, its workers, its people, its taxpayers."” To date there have been no specific details as to how this will be accomplished.

PNM will continue to monitor the United States’ involvement in international accords, and believes that implementation of the BART plan for SJGS (Note 11), as well asbut the potential exit fromimpact that such accords may have on the remaining SJGS units and Four Corners as discussed in Note 12 should provide a significant step for New Mexico to comply with the Clean Power Plan, or other GHG reduction requirements, should they prevail.Company cannot be determined at this time.


Assessment of Legislative/Regulatory Impacts

The Company has assessed, and continues to assess, the impacts of climate change legislation orand 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 specific GHG limits; the timing of implementation of these limits; the possibility of a market-based trading program, including the associated costs and the availability of emission credits or allowances; the development of emission reduction and/or renewable energy technologies; 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 are, at best, preliminary and speculative. However, based upon these assumptions, the enactment of climate change legislation or regulation 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 Notes 11 and 12.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 too preliminary and speculative at this time for a meaningful prediction of financial impact.


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.

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. The Trump Administration has indicated that the provisions of the Dodd-Frank Reform Act will be reviewed and certain regulations may be rolled back, but no formal action has been taken.taken yet. 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

See Notes 11 and 12 herein and Notes 16 and 17 of the Notes to Consolidated Financial Statements in the 20162017 Annual Reports on Form 10-K for a discussion of commitments and contingencies and rate and regulatory matters. See Note 1 for a discussion of accounting pronouncements that have been issued, but are not yet effective and have not been adopted by the Company.


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 SeptemberJune 30, 20172018, there have been no significant changes with regard to the critical accounting policies disclosed in PNMR’s, PNM’s, and TNMP’s 20162017 Annual Reports on Forms 10-K. The policies disclosed included unbilled revenues, regulatory accounting, impairments, decommissioning and reclamation costs, pension and other postretirement benefits, accounting for contingencies, and income taxes, and market risk.taxes.

MD&A FOR PNM

RESULTS OF OPERATIONS

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

MD&A FOR TNMP

RESULTS OF OPERATIONS

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

DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

Statements made in this filing that relate to future events or PNMR’s, PNM’s, or TNMP’s expectations, projections, estimates, intentions, goals, targets, and strategies are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that all forward-looking statements are based upon current expectations and estimates. PNMR, PNM, and TNMP assume no obligation to update this information.
 
Because actual results may differ materially from those expressed or implied by these forward-looking statements, PNMR, PNM, and TNMP caution readers not to place undue reliance on these statements. PNMR’s, PNM’s, and TNMP’s business, financial condition, cash flows, and operating results are influenced by many factors, which are often beyond their control, that can cause actual results to differ from those expressed or implied by the forward-looking statements. These factors include:

The ability of PNM and TNMP to recover costs and earn allowed returns in regulated jurisdictions, including the impacts of the NMPRC orderorders in PNM’s NM 2015 Rate Case appeals of that order, PNM’sand NM 2016 Rate Case, appeals of those orders, the deferral of the issue of PNM’s 2018 renewable procurement plan,prudence of continuation of participation in Four Corners to PNM’s next rate case and recovery of PNM’s investments in that plant, any actions resulting from PNM’s 2017 IRP, and the TNMP 2018 Rate Case (collectively, the “Regulatory Proceedings”) and the impact on service levels for PNM customers if the ultimate outcomes do not providep

rovide for the recovery of costs of operating and capital expenditures, as well as other impacts of federal or state regulatory and judicial actions
The ability of the Company to successfully forecast and manage its operating and capital expenditures, including aligning expenditures with the revenue levels resulting from the ultimate outcomes in PNM’s NM 2015 Rate Case, including appeals, PNM’s NM 2016 Rate Case, and TNMP’s rate case anticipated to be filed in 2018of the Regulatory Proceedings and supporting forecasts utilized in future test year rate proceedings
The impacts on the electricity usage of customers and consumers due to performance of state, regional, and national economies, 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
Uncertainty surrounding the status of PNM’s participation in jointly-owned generation projects, including the 2022 scheduled expiration of the operational and fuel supply agreements for SJGS, as well as the 2018 required NMPRC filing to determine the extent to which SJGS should continue serving PNM’s retail customers beyond mid-2022 and any actions resulting from PNM’s 2017 IRP, including regulatory recovery of undepreciated investments in the event the NMPRC orders generating facilities to be retired before currently scheduled
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, including the potential impacts of the orderultimate outcomes of the Regulatory Proceedings
The impacts on the electricity usage of customers and consumers due to performance of state, regional, and national economies, energy efficiency measures, weather, seasonality, alternative sources of power, and other changes in the NM 2015 Rate Case, appeals of that order, the ultimate outcome of PNM’s NM 2016 Rate Case,supply and PNM’s 2017 IRPdemand

��Uncertainty regarding what actions PNM may take with respect to the generating capacity in PVNGS Units 1 and 2, which is under lease, at the expiration of the lease terms in 2023 and 2024, as well as the related treatment for ratemaking purposes by the NMPRC
The Company’s ability to access the financial markets in order to provide financing to repay or refinance debt as it comes due, as well as for ongoing operations and construction expenditures, including disruptions in the capital or credit markets, actions by ratings agencies, and fluctuations in interest rates, including any negative impacts that could result from the ultimate outcome in PNM’s NM 2015 Rate Case, including appeals,outcomes of the Regulatory Proceedings
The risks associated with completion of generation, transmission, distribution, and PNM’s NM 2016 Rate Caseother projects
The potential unavailability of cash from PNMR’s subsidiaries due to regulatory, statutory, or contractual restrictions or subsidiary earnings or cash flows
State and federal regulation or legislation relating to environmental matters, the resultant costs of compliance, and other impacts on the operations and economic viability of PNM’s generating plants
Risks related to climate change, including potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit GHG, including the Clean Power Plan
Uncertainty surrounding counterparty credit risk, including financial support provided to facilitate the coal supply and ownership restructuring at SJGS
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
State and federal regulation or legislation relating to environmental matters, the resultant costs of compliance, and other impacts on the operations and economic viability of PNM’s generating plants
State and federal regulatory, legislative, executive, and judicial decisions and actions on ratemaking, tax, including the potential forimpacts and related uncertainties of tax reform enacted in 2017, and other matters
Risks related to climate change, including potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit GHG
Employee workforce factors, including cost control efforts and 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
The risks associated with completion of generation, transmission, distribution, and other projects
Regulatory, financial, and operational risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainties
The risk that FERC rulemakings or lack of additional capacity during peak hours may negatively impact the operation of PNM’s transmission system
The impacts of decreases in the values of marketable securities maintained in trusts to provide for decommissioning, reclamation, pension benefits, and other postretirement benefits, including potential increased volatility resulting from international developments
Uncertainty surrounding counterparty credit risk, including financial support provided to facilitate the coal supply at SJGS
The effectiveness of risk management regarding commodity transactions and counterparty risk
The outcome of legal proceedings, including the extent of insurance coverage
Changes in applicable accounting principles or policies

Any material changes to risk factors occurring after the filing of PNMR’s, PNM’s, and TNMP’s 20162017 Annual Reports on Form 10-K are disclosed in Item 1A, Risk Factors, in Part II of this Form 10-Q.

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


SECURITIES ACT DISCLAIMER

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

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


Our corporate Internet addresses are:
 
PNMR: www.pnmresources.com
PNM: www.pnm.com
TNMP: www.tnmp.com
 
The PNMR website includes a link to PNMR’s Sustainability Portal, www.pnmresources.com/about-us/sustainability-portal.aspx.sustainability-portal.aspx. This portal provides access to key sustainability information, including a Climate Change Report, related to the operations of PNM and TNMP and reflects PNMR’s commitment to do business in an ethical, open, and transparent manner.

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 http://www.pnmresources.com/corporate-governance.aspx and in print upon request from any shareholder are PNMR’s:
 
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
Restated Articles of Incorporation and Bylaws
 
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 market risk through a comprehensive set of policies and procedures with oversight by senior level management through the RMC.Risk Management Committee (“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
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 ninesix months ended SeptemberJune 30, 20172018 and the year ended December 31, 2016,2017, 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 the net asset or liability balance sheet position for mark-to-market energy transactions.
Nine Months EndedSix Months Ended
September 30,June 30,
2017 20162018 2017
Economic Hedges(In thousands)(In thousands)
Sources of fair value gain (loss):      
Net fair value at beginning of period$2,885
 $4,576
$(94) $2,885
Amount realized on contracts delivered during period(1,266) (1,294)54
 (3,597)
Changes in fair value408
 (899)2
 2,657
Net mark-to-market change recorded in earnings(858) (2,193)56
 (940)
Net change recorded as regulatory assets and liabilities(213) (168)(284) (88)
Net fair value at end of period$1,814
 $2,215
$(322) $1,857
The following table provides the maturityAll of the net assets (liabilities), giving an indicationfair values as of when theseJune 30, 2018 were determined based on prices provided by external sources other than actively quoted market prices. The net mark-to-market amounts will settle and generate (use) cash.

Fair Value of Mark-to-Market Instruments at September 30, 2017
 Settlement Dates
 2017 2018
 (In thousands)
Economic hedges   
Prices actively quoted$—
 $—
Prices provided by other external sources1,814
 —
Prices based on models and other valuations—
 —
Total$1,814
 $—
in 2018.

PNM is exposed to changes in the market prices of electricity and natural gas for the positions in its wholesale portfolio (notnot covered by the FPPAC).FPPAC. The Company manages risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options, and swaps. PNM uses such instruments to hedge its exposure to changes in the market prices of electricity and natural gas. PNM also uses such instruments under an NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC.

Prior to 2018, PNM measuresmeasured the market risk of its wholesale activities not covered by the FPPAC using a Monte Carlo VaR simulation model to report the possible loss in value from price movements. In January 2018, PNM’s interest in PVNGS Unit 3 became a jurisdictional resource to serve New Mexico customers and PNM began selling 36 MW of its 65 MW merchant interest in SJGS Unit 4 to a third party at a fixed price. These events significantly reduced PNM’s exposure to commodity risk and, beginning in February 2018, the Company no longer uses VaR is notas 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, 2017, the high, low, and average VaR amounts were $0.7 million, $0.1 million, and $0.4 million. For the year ended December 31, 2016, the high, low, and average VaR amounts were $1.3 million, $0.3 million, and $0.6 million. At September 30, 2017 and December 31, 2016, the VaR amounts for the PNM wholesale portfolio were $0.2 million and $0.6 million.
The VaR represents 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 is 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 fluctuations in

market prices, operating exposures, and the timing thereof, as well as changes to the underlying portfolios during the year.metric. VaR limits were not exceeded during the nine months ended September 30, 2017 or the year ended December 31, 2016.2017.

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 credit exposure by the credit worthiness (credit rating) and concentration of credit risk for wholesale counterparties, all of which will mature in less than two years.

Schedule of Credit Risk Exposure
SeptemberJune 30, 20172018
Rating (1)
Credit Risk Exposure(2)
 Number of Counter-parties >10% Net Exposure of Counter-parties >10%
Credit Risk Exposure(2)
 Number of Counter-parties >10% Net Exposure of Counter-parties >10%
(Dollars in thousands)(Dollars in thousands)
External ratings:      
Investment grade$1,778
 — $—
$916
 2 $644
Non-investment grade10
 — —
1
 — —
Split ratings566
  138
 — —
Internal ratings:      
Investment grade1,029
 1 949
567
 1 377
Non-investment grade4,492
 1 4,476
—
 — —
Total$7,875
 $5,425
$1,622
 $1,021
(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)the Tri-State hazard sharing agreement), forward sales, and short-term sales. The gross exposure captures the amounts from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses. Gross exposures can be offset according to legally enforceable netting arrangements, but are not reduced by posted credit collateral. At June 30, 2018, PNMR held $1.9 million of cash collateral to offset its credit exposure.
    
Net credit risk for the Company’s largest counterparty as of SeptemberJune 30, 20172018 was $4.5$0.4 million.

As discussed in Note 11, PNMR’s subsidiary, NM Capital, entered into the Westmoreland Loan to facilitate the acquisition of SJCC by WSJ, a subsidiary of Westmoreland, and PNMR has arranged for letters of credit to be issued to support the coal mining operations of SJCC. PNMR is exposed to credit risk under these arrangements in the event of default by WSJ. As of October 20, 2017, remaining required principal payments under the Westmoreland Loan are $9.6 million in 2017, $3.6 million in 2018, $8.6 million in 2019, $23.3 million in 2020, and $21.1 million in 2021. As of October 20, 2017, $11.4 million was held in a SJCC restricted bank account that will be used solely to make the November 1, 2017 scheduled principal payment of $9.6 million and interest on the Westmoreland Loan. In addition, the Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations, the value of which PNMR believes approximates the amount outstanding under the Westmoreland Loan.  Furthermore, PNMR considers the possibility of loss under the letters of credit to be remote as discussed in Note 5. Accordingly, PNMR does not consider its credit risk under these arrangements to be material.

Other investments have no significant counterparty credit risk.


Interest Rate Risk

The majority of the Company’s long-term debt is fixed-rate debt and does not expose earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of PNMR’s consolidated long-term debt instruments would increase by 1.6%2.2%, or $41.0$58.2 million if interest rates were to decline by 50 basis points from their levels at SeptemberJune 30, 2017.2018. 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 20, 2017,July 25, 2018, PNMR, PNM, TNMP, and TNMPPNMR Development had short-term debt outstanding of $175.1$111.0 million, none,$8.8 million, $6.2 million, and $5.9$24.5 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.TNMP, and $24.5 million for PNMR Development. PNM also had no borrowings of $10.0 million under the $50.0$40.0 million PNM 2017 New Mexico Credit Facility at October 20, 2017.July 25, 2018. The revolving credit facilities, the PNM 2017 New Mexico Credit Facility, the $150.0 million PNMR 2015 Term Loan Agreement, the $100.0 million PNMR 2016 One-Year Term Loan Agreement (as extended), the $100.0 million PNMR 2016 Two-Year Term Loan Agreement, the $200.0 million PNM 2017 Term Loan Agreement, and the $125.0$20.0 million BTMUTNMP 2018 Term Loan Agreement bear interest at variable rates. On October 20, 2017,July 25, 2018, interest rates on borrowings averaged 2.49%3.34% for the PNMR Revolving Credit Facility, 2.14% for the PNMR 2015 Term Loan Agreement, 4.06% for the BTMU Term Loan Agreement, 2.09%2.89% for the PNMR 2016 One-Year Term Loan Agreement 2.19%(as extended), 2.85% for the PNMR 2016 Two-Year Term Loan Agreement, 1.97%3.20% for the PNM Revolving Credit Facility, 3.21% for the PNM 2017 New Mexico Credit Facility, 2.83% for the PNM 2017 Term Loan Agreement, and 1.99%2.83% for the TNMP Revolving Credit Facility, 2.76% for the TNMP 2018 Term Loan Agreement, and 3.08% for the PNMR Development Revolving Credit Facility. The Company is exposed to interest rate risk to the extent of future increases in variable interest rates. However, as discussed in Note 9, PNMR has entered into hedging arrangements to effectively establish fixed interest rates on the PNMR 2015 Term Loan Agreement and $150.0 million of variable rate debt.

The investments held by PNM in trusts for decommissioning and reclamation had an estimated fair value of $306.4$323.1 million at SeptemberJune 30, 2017,2018, of which 35.8%62.2% were fixed-rate debt securities that subject PNM to risk of loss of fair value with increases in market interest rates. If interest rates were to increase by 50 basis points from their levels at SeptemberJune 30, 2017,2018, the decrease in the fair value of the fixed-rate securities would be 3.7%2.8%, or $4.1$5.6 million. Due to the current funded status of the NDT and overall market performance, PNM has begun to evaluate whether to re-balance the NDT investment portfolio with a target of increasing the percentage of the investments in fixed income (debt) securities. Such a portfolio re-balancing would be expected to increase the exposure related to interest rate risks and reduce the equity market risk referenced below.

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. However, as described in Note 12, the NMPRC has ruled that PNM would not be able to include future contributions made by PNM for decommissioning of PVNGS, to the extent applicable to certain capacity previously leased by PNM, in rates charged to retail customers. PNM has appealed the NMPRC’s ruling to the NM Supreme Court. 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 SeptemberJune 30, 2017.2018. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 61.6%35.3% of the securities held by the trusts as of SeptemberJune 30, 2017.2018. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $18.9$11.4 million.



ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

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

Changes in internal controls over financial reporting

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 SeptemberJune 30, 20172018 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 – Four Corners Federal Agency Lawsuit
WEG v. OSM NEPA Lawsuit
Navajo Nation Environmental Issues
Santa Fe Generating Station
Coal Supply – Four Corners – Four Corners Coal Supply Arbitration
Continuous Highwall Mining Royalty Rate
PVNGS Water Supply Litigation
San Juan River Adjudication
Rights-of-Way Matter
Navajo Nations Allottee Matters
Sales Tax Audits
Note 12

PNM – New Mexico General Rate Cases
PNM – Renewable Portfolio Standard
PNM – Renewable Energy Rider
PNM – Energy Efficiency and Load Management
PNM – Integrated Resource Plans
PNM – San Juan Generating Station Units 2 and 3 Retirement
PNM – Advanced Metering Infrastructure ApplicationUnit 1 Outage
TNMP – Transmission Cost of Service RatesTNMP 2018 Rate Case
TNMP – Energy EfficiencyOrder Related to Changes in Federal Income Tax Rates



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, 2016.2017.

ITEM 5. OTHER INFORMATION

July 2018 Offering of PNM 2018 SUNs

On July 31, 2018, PNM issued an aggregate $100.0 million of PNM 2018 SUNs in the following series and denominations: (i) $15.0 million aggregate principal amount of its 3.78% Senior Unsecured Notes, Series D, due August 1, 2028 (the “Series D Notes”) and (ii) $85.0 million aggregate principal amount of its 4.60% Senior Unsecured Notes, Series H, due August 1, 2048 (the “Series H Notes” and, together with the Series D Notes, the “PNM July 2018 SUNs”). The PNM July 2018 SUNs were sold in a private placement transaction in reliance on an exemption from registration under the Securities Act of 1933, as amended (the “Securities Act”). PNM sold the PNM July 2018 SUNs to institutional accredited investors (as defined by Rule 501(a) of the Securities Act), pursuant to the PNM 2017 Senior Unsecured Note Agreement. Interest on the PNM July 2018 SUNs is payable semiannually on February 1 and August 1 of each year, commencing on February 1, 2019.

PNM intends to use the gross proceeds from the PNM July 2018 SUNs to repay $100.0 million of its 7.50% SUNs that mature on August 1, 2018.

The terms of the PNM 2017 Senior Unsecured Note Agreement, which continue to apply so long as any of the PNM 2018 SUNs are outstanding, include customary covenants, including a covenant that requires PNM to maintain a debt-to-capitalization ratio of less than or equal to 65%, customary events of default, including a cross default provision, and covenants regarding parity of financial covenants, liens and guarantees with respect to PNM’s material credit facilities. In the event of a change of control, PNM will be required to offer to prepay the PNM 2018 SUNs at par. PNM may, on not less than ten nor more than sixty days’ prior written notice, prepay at any time all, or from time to time part of, the PNM 2018 SUNs of any series, in an amount not less than twenty percent of the aggregate principal amount of the PNM 2018 SUNs of such series, prior to their respective maturities, subject to payment of a customary make-whole premium.

The above description of the PNM 2017 Senior Unsecured Note Agreement and the PNM July 2018 SUNs does not purport to be a complete statement of the parties’ rights and obligations thereunder. Such description is qualified in its entirety by reference to the PNM 2017 Senior Unsecured Note Agreement, which is incorporated herein by reference, a copy of which was attached as Exhibit 10.1 to PNM’s Quarterly Report on Form 10-Q filed with the SEC on July 28, 2017. The forms of each of the PNM July 2018 SUNs was attached to the PNM 2017 Senior Unsecured Note Agreement as Schedule 1-D and Schedule 1-H, respectively, and each is incorporated herein by reference.

The PNM July 2018 SUNs are not registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements and applicable state laws. This Quarterly Report on Form 10-Q does not constitute an offer to sell nor a solicitation of an offer to purchase the PNM July 2018 SUNs or any other securities, and shall not constitute an offer, solicitation or sale in any state or jurisdiction in which such an offer, solicitation or sale would be unlawful.

Amendment to PNMR Revolving Credit Facility

On July 30, 2018, PNMR amended the PNMR Revolving Credit Facility by entering into the Sixth Amendment to and Restatement of Credit Agreement (the “Sixth Amendment”) amending and restating the Credit Agreement dated as of October 31, 2011 among PNMR, the lenders party thereto, Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent and MUFG Union Bank, N.A. (“MUFG”), as syndication agent, as previously amended.

The Sixth Amendment is effective as of July 30, 2018, and (i) increases the PNMR consolidated debt-to-consolidated capitalization ratio to 0.7 to 1.0, (ii) permits the maturity date to be extended from October 31, 2022 to October 31, 2024 through the exercise of two additional one-year extension options, subject to the approval by a majority of the lenders, (iii) changes the letter of credit sublimit from $200.0 million to $90.0 million, and in connection therewith reduces the letter of credit commitment of Wells Fargo to $22.5 million and of MUFG to $22.5 million, and (iv) contains various other amendments, including changes to certain definitions, interest payment dates, events of default, and permitted asset sales provisions, among others.



Amendments to PNMR 2016 One-Year Term Loan and PNMR 2016 Two-Year Term Loan
On July 30, 2018, PNMR amended its PNMR 2016 One-Year Term Loan and its PNMR 2016 Two-Year Term Loan by entering into: (i) the Second Amendment to Term Loan Agreement (“Amendment No. 2 to PNMR 2016 One-Year Term Loan”), amending its $100.0 million term loan agreement, dated December 21, 2016 among PNMR, the lender parties thereto (Wells Fargo, MUFG, and The Bank of New York Mellon), and Wells Fargo, as administrative agent and (ii) the Second Amendment to Term Loan Agreement (“Amendment No. 2 to PNMR 2016 Two-Year Term Loan” and, together with Amendment No. 2 to PNMR 2016 One-Year Term Loan, the “PNMR Term Loan Amendments”), amending its $100.0 million term loan agreement, dated December 21, 2016, among PNMR and JPMorgan Chase Bank, N.A. (“JPMorgan”), as lender and administrative agent.
The PNMR Term Loan Amendments are effective as of July 30, 2018 and (i) increase the PNMR consolidated debt-to-consolidated capitalization ratio to 0.7 to 1.0 and (ii) contain various other amendments, including changes to certain definitions, interest payment dates, events of default and permitted asset sales provisions, among others.
Wells Fargo, JPMorgan, MUFG, The Bank of New York Mellon and the other lender parties to the PNMR Revolving Credit Facility, and their affiliates perform normal banking (including as lenders under other loans and facilities) and investment banking and advisory services from time to time for PNMR and its affiliates, for which they receive customary fees and expenses.





ITEM 6. EXHIBITS
3.1PNMR
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)
   
3.2PNM
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)
   
3.3TNMP
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)
   
3.4PNMR
Bylaws of PNMR, with all amendments to and including October 24, 2017 (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed October 25, 2017)
   
3.5PNM
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)
   
3.6TNMP
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)
10.1PNM
New Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement made as of September 1, 2017 among PNM, Tuscon Electric Power Company, The City of Farmington, New Mexico, The Incorporated County of Los Alamos, New Mexico, and Utah Associated Municipal Power Systems
   
12.1PNMR
Ratio of Earnings to Fixed Charges
   
12.2PNM
Ratio of Earnings to Fixed Charges
   
12.3TNMP
Ratio of Earnings to Fixed Charges
   
31.1PNMR
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
31.2PNMR
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
31.3PNM
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
31.4PNM
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
31.5TNMP
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
31.6TNMP
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
   
32.1PNMR
Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
32.2PNM
Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
32.3TNMP
Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
101.INSPNMR, PNM, and TNMPXBRL Instance Document
   

101.SCHPNMR, PNM, and TNMPXBRL Taxonomy Extension Schema Document
   
101.CALPNMR, PNM, and TNMPXBRL Taxonomy Extension Calculation Linkbase Document
   
101.DEFPNMR, PNM, and TNMPXBRL Taxonomy Extension Definition Linkbase Document
   
101.LABPNMR, PNM, and TNMPXBRL Taxonomy Extension Label Linkbase Document
   
101.PREPNMR, PNM, and TNMPXBRL Taxonomy Extension Presentation Linkbase Document

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 27, 2017July 31, 2018/s/ Joseph D. Tarry
  Joseph D. Tarry
  Vice President, Finance and Controller
  (Officer duly authorized to sign this report)

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