[X] | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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 |
PNM Resources, Inc. (“PNMR”) | YES | ü | NO | ||
Public Service Company of New Mexico (“PNM”) | YES | ü | NO | ||
Texas-New Mexico Power Company (“TNMP”) | YES | NO | ü |
PNMR | YES | ü | NO | ||
PNM | YES | ü | NO | ||
TNMP | YES | ü | NO |
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 |
Page No. | |
Definitions: | ||
2014 IRP | PNM’s 2014 IRP | |
2017 IRP | PNM’s 2017 IRP | |
ABCWUA | Albuquerque Bernalillo County Water Utility Authority | |
AEP OnSite Partners | AEP 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 | |
ARP | Alternative Revenue Program | |
ASU | Accounting Standards Update | |
August 2016 RD | Recommended 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 | |
BHP | BHP 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 | |
BTU | British Thermal Unit | |
CAA | Clean Air Act | |
CCB | Coal Combustion Byproducts | |
CCN | Certificate of Convenience and Necessity | |
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 | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
FIP | Federal Implementation Plan | |
Four Corners | Four Corners Power Plant | |
FPPAC | Fuel and Purchased Power Adjustment Clause | |
FTY | Future Test Year | |
GAAP | Generally Accepted Accounting Principles in the United States of America | |
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 | |
Luna | Luna Energy Facility | |
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
MMBTU | Million BTUs | |
Moody’s | Moody’s Investor Services, Inc. | |
MW | Megawatt | |
MWh | Megawatt Hour | |
NAAQS | National Ambient Air Quality Standards | |
Navajo Acts | Navajo Nation Air Pollution Prevention and Control Act, Navajo Nation Safe Drinking Water Act, and Navajo Nation Pesticide Act | |
NDT | Nuclear Decommissioning Trusts for PVNGS | |
NEC | Navopache Electric Cooperative, Inc. | |
NEE | New Energy Economy | |
NEPA | National Environmental Policy Act | |
NERC | North American Electric Reliability Corporation | |
New Mexico Wind | New Mexico Wind Energy Center | |
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 Court | United 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 | |
NMRD | NM Renewable Development, LLC, owned 50% each by PNMR Development and AEP OnSite Partners, LLC | |
NOx | Nitrogen Oxides | |
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-Employment Benefits | |
OSM | United States Office of Surface Mining Reclamation and Enforcement | |
PNM | Public Service Company of New Mexico and Subsidiaries | |
PNM 2017 New Mexico Credit Facility | PNM’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 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 SUNs | PNMR’s $300.0 Million Aggregate Principal Amount of Senior Unsecured Notes due 2021 | |
PNMR Development | PNMR Development and Management Company, an unregulated wholly-owned subsidiary of PNMR | |
PNMR Development Revolving Credit Facility | PNMR 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 | |
PSD | Prevention of Significant Deterioration | |
PUCT | Public Utility Commission of Texas | |
PV | Photovoltaic | |
PVNGS | Palo Verde Nuclear Generating Station | |
RCRA | Resource Conservation and Recovery Act | |
RCT | Reasonable Cost Threshold | |
REA | New Mexico’s Renewable Energy Act of 2004 | |
REC | Renewable Energy Certificates | |
Red Mesa Wind | Red Mesa Wind Energy Center | |
REP | Retail Electricity Provider | |
RFP | Request For Proposal | |
Rio Bravo | Rio Bravo Generating Station | |
RMC | Risk 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 CSA | San Juan Generating Station Coal Supply Agreement | |
SJGS RA | San Juan Project Restructuring Agreement | |
SJPPA | San Juan Project Participation Agreement | |
SNCR | Selective Non-Catalytic Reduction | |
SO2 | Sulfur Dioxide | |
TECA | Texas Electric Choice Act | |
Tenth Circuit | United States Court of Appeals for the Tenth Circuit | |
TNMP | Texas-New Mexico Power Company and Subsidiaries | |
TNMP Revolving Credit Facility | TNMP’s $75.0 Million Secured Revolving Credit Facility | |
Tri-State | Tri-State Generation and Transmission Association, Inc. | |
US Supreme Court | United States Supreme Court | |
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 to WSJ | |
WSJ | Westmoreland San Juan, LLC, an indirect wholly-owned subsidiary of Westmoreland |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands, except per share amounts) | |||||||
Electric Operating Revenues: | |||||||
Contracts with customers | $ | 303,351 | $ | 297,191 | |||
Alternative revenue programs | 924 | 4,579 | |||||
Other electric operating revenue | 13,603 | 28,408 | |||||
Total electric operating revenues | 317,878 | 330,178 | |||||
Operating Expenses: | |||||||
Cost of energy | 92,556 | 102,804 | |||||
Administrative and general | 48,283 | 45,394 | |||||
Energy production costs | 35,350 | 31,787 | |||||
Depreciation and amortization | 58,722 | 56,383 | |||||
Transmission and distribution costs | 16,955 | 16,477 | |||||
Taxes other than income taxes | 19,880 | 19,235 | |||||
Total operating expenses | 271,746 | 272,080 | |||||
Operating income | 46,132 | 58,098 | |||||
Other Income and Deductions: | |||||||
Interest income | 4,124 | 4,881 | |||||
Gains on investment securities | 288 | 6,661 | |||||
Other income | 3,469 | 4,902 | |||||
Other (deductions) | (1,376 | ) | (5,621 | ) | |||
Net other income and deductions | 6,505 | 10,823 | |||||
Interest Charges | 33,055 | 31,700 | |||||
Earnings before Income Taxes | 19,582 | 37,221 | |||||
Income Taxes | 783 | 10,775 | |||||
Net Earnings | 18,799 | 26,446 | |||||
(Earnings) Attributable to Valencia Non-controlling Interest | (3,677 | ) | (3,452 | ) | |||
Preferred Stock Dividend Requirements of Subsidiary | (132 | ) | (132 | ) | |||
Net Earnings Attributable to PNMR | $ | 14,990 | $ | 22,862 | |||
Net Earnings Attributable to PNMR per Common Share: | |||||||
Basic | $ | 0.19 | $ | 0.29 | |||
Diluted | $ | 0.19 | $ | 0.29 | |||
Dividends Declared per Common Share | $ | 0.2650 | $ | 0.2425 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Net Earnings | $ | 18,799 | $ | 26,446 | |||
Other Comprehensive Income: | |||||||
Unrealized Gains on Available-for-Sale Securities: | |||||||
Unrealized holding gains arising during the period, net of income tax (expense) of $(283) and $(3,030) | 832 | 4,736 | |||||
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $668 and $1,078 | (1,961 | ) | (1,685 | ) | |||
Pension Liability Adjustment: | |||||||
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(480) and $(631) | 1,411 | 987 | |||||
Fair Value Adjustment for Cash Flow Hedges: | |||||||
Change in fair market value, net of income tax (expense) benefit of $(472) and $72 | 1,386 | (113 | ) | ||||
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $13 and $(44) | (40 | ) | 68 | ||||
Total Other Comprehensive Income | 1,628 | 3,993 | |||||
Comprehensive Income | 20,427 | 30,439 | |||||
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (3,677 | ) | (3,452 | ) | |||
Preferred Stock Dividend Requirements of Subsidiary | (132 | ) | (132 | ) | |||
Comprehensive Income Attributable to PNMR | $ | 16,618 | $ | 26,855 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Cash Flows From Operating Activities: | |||||||
Net earnings | $ | 18,799 | $ | 26,446 | |||
Adjustments to reconcile net earnings to net cash flows from operating activities: | |||||||
Depreciation and amortization | 67,748 | 65,888 | |||||
Deferred income tax expense | 767 | 10,787 | |||||
Net unrealized (gains) on commodity derivatives | (28 | ) | (1,345 | ) | |||
(Gains) on investment securities | (288 | ) | (6,661 | ) | |||
Stock based compensation expense | 2,894 | 2,687 | |||||
Allowance for equity funds used during construction | (2,487 | ) | (1,632 | ) | |||
Other, net | 757 | 704 | |||||
Changes in certain assets and liabilities: | |||||||
Accounts receivable and unbilled revenues | 18,215 | 20,553 | |||||
Materials, supplies, and fuel stock | (2,976 | ) | 1,836 | ||||
Other current assets | 2,345 | 11,441 | |||||
Other assets | (443 | ) | 2,753 | ||||
Accounts payable | (26,953 | ) | (3,852 | ) | |||
Accrued interest and taxes | 13,370 | 12,542 | |||||
Other current liabilities | (9,397 | ) | (10,009 | ) | |||
Other liabilities | (3,397 | ) | (534 | ) | |||
Net cash flows from operating activities | 78,926 | 131,604 | |||||
Cash Flows From Investing Activities: | |||||||
Additions to utility and non-utility plant | (117,691 | ) | (114,830 | ) | |||
Proceeds from sales of investment securities | 626,729 | 266,388 | |||||
Purchases of investment securities | (628,999 | ) | (267,891 | ) | |||
Principal repayments on Westmoreland Loan | 5,649 | 9,590 | |||||
Investments in NMRD | (5,000 | ) | — | ||||
Other, net | 128 | 128 | |||||
Net cash flows from investing activities | (119,184 | ) | (106,615 | ) |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Cash Flows From Financing Activities: | |||||||
Revolving credit facilities borrowings (repayments), net | (66,700 | ) | 16,000 | ||||
Long-term borrowings | 299,652 | — | |||||
Repayment of long-term debt | (155,026 | ) | (9,444 | ) | |||
Proceeds from stock option exercise | 802 | 1,112 | |||||
Awards of common stock | (10,845 | ) | (11,032 | ) | |||
Dividends paid | (21,240 | ) | (19,448 | ) | |||
Valencia’s transactions with its owner | (4,472 | ) | (4,028 | ) | |||
Other, net | (2,104 | ) | (388 | ) | |||
Net cash flows from financing activities | 40,067 | (27,228 | ) | ||||
Change in Cash, Restricted Cash, and Equivalents | (191 | ) | (2,239 | ) | |||
Cash, Restricted Cash, and Equivalents at Beginning of Period | 3,974 | 5,522 | |||||
Cash, Restricted Cash, and Equivalents at End of Period | $ | 3,783 | $ | 3,283 | |||
Restricted Cash Included in Other Current Assets on Condensed Consolidated Balance Sheets: | |||||||
At beginning of period | $ | — | $ | 1,000 | |||
At end of period | $ | — | $ | 1,000 | |||
Supplemental Cash Flow Disclosures: | |||||||
Interest paid, net of amounts capitalized | $ | 15,305 | $ | 14,951 | |||
Income taxes paid (refunded), net | $ | (8 | ) | $ | (125 | ) | |
Supplemental schedule of noncash investing activities: | |||||||
(Increase) decrease in accrued plant additions | $ | 16,003 | $ | 10,367 |
March 31, 2018 | December 31, 2017 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 3,783 | $ | 3,974 | |||
Accounts receivable, net of allowance for uncollectible accounts of $1,118 and $1,081 | 84,156 | 90,473 | |||||
Unbilled revenues | 41,400 | 54,055 | |||||
Other receivables | 17,891 | 17,582 | |||||
Current portion of Westmoreland Loan | 4,837 | 3,576 | |||||
Materials, supplies, and fuel stock | 69,478 | 66,502 | |||||
Regulatory assets | 1,423 | 2,933 | |||||
Commodity derivative instruments | 1,087 | 1,088 | |||||
Income taxes receivable | 6,855 | 6,879 | |||||
Other current assets | 46,389 | 47,358 | |||||
Total current assets | 277,299 | 294,420 | |||||
Other Property and Investments: | |||||||
Long-term portion of Westmoreland Loan | 46,154 | 53,064 | |||||
Investment securities | 324,003 | 323,524 | |||||
Equity investment in NMRD | 21,541 | 16,510 | |||||
Other investments | 375 | 503 | |||||
Non-utility property | 3,404 | 3,404 | |||||
Total other property and investments | 395,477 | 397,005 | |||||
Utility Plant: | |||||||
Plant in service and held for future use | 7,284,727 | 7,238,285 | |||||
Less accumulated depreciation and amortization | 2,627,329 | 2,592,692 | |||||
4,657,398 | 4,645,593 | ||||||
Construction work in progress | 284,870 | 245,933 | |||||
Nuclear fuel, net of accumulated amortization of $49,905 and $43,524 | 89,262 | 88,701 | |||||
Net utility plant | 5,031,530 | 4,980,227 | |||||
Deferred Charges and Other Assets: | |||||||
Regulatory assets | 595,398 | 600,672 | |||||
Goodwill | 278,297 | 278,297 | |||||
Commodity derivative instruments | 3,277 | 3,556 | |||||
Other deferred charges | 95,115 | 91,926 | |||||
Total deferred charges and other assets | 972,087 | 974,451 | |||||
$ | 6,676,393 | $ | 6,646,103 |
March 31, 2018 | December 31, 2017 | ||||||
(In thousands, except share information) | |||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | 238,700 | $ | 305,400 | |||
Current installments of long-term debt | 309,565 | 256,895 | |||||
Accounts payable | 78,427 | 121,383 | |||||
Customer deposits | 11,045 | 11,028 | |||||
Accrued interest and taxes | 75,703 | 62,357 | |||||
Regulatory liabilities | 3,159 | 2,309 | |||||
Commodity derivative instruments | 1,328 | 1,182 | |||||
Dividends declared | 21,240 | 21,240 | |||||
Other current liabilities | 43,586 | 53,850 | |||||
Total current liabilities | 782,753 | 835,644 | |||||
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | 2,271,984 | 2,180,750 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes | 554,022 | 547,210 | |||||
Regulatory liabilities | 934,053 | 933,578 | |||||
Asset retirement obligations | 149,453 | 146,679 | |||||
Accrued pension liability and postretirement benefit cost | 88,840 | 94,003 | |||||
Commodity derivative instruments | 3,277 | 3,556 | |||||
Other deferred credits | 131,468 | 131,706 | |||||
Total deferred credits and other liabilities | 1,861,113 | 1,856,732 | |||||
Total liabilities | 4,915,850 | 4,873,126 | |||||
Commitments and Contingencies (See Note 11) | |||||||
Cumulative Preferred Stock of Subsidiary | |||||||
without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares) | 11,529 | 11,529 | |||||
Equity: | |||||||
PNMR common stockholders' equity: | |||||||
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares) | 1,150,516 | 1,157,665 | |||||
Accumulated other comprehensive income (loss), net of income taxes | (105,520 | ) | (95,940 | ) | |||
Retained earnings | 638,618 | 633,528 | |||||
Total PNMR common stockholders’ equity | 1,683,614 | 1,695,253 | |||||
Non-controlling interest in Valencia | 65,400 | 66,195 | |||||
Total equity | 1,749,014 | 1,761,448 | |||||
$ | 6,676,393 | $ | 6,646,103 | ||||
Attributable to PNMR | Non- controlling Interest in Valencia | ||||||||||||||||||||||
Common Stock | AOCI | Retained Earnings | Total PNMR Common Stockholders’ Equity | Total Equity | |||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
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 adjusted | 1,157,665 | (107,148 | ) | 644,736 | 1,695,253 | 66,195 | 1,761,448 | ||||||||||||||||
Net earnings before subsidiary preferred stock dividends | — | — | 15,122 | 15,122 | 3,677 | 18,799 | |||||||||||||||||
Total other comprehensive income | — | 1,628 | — | 1,628 | — | 1,628 | |||||||||||||||||
Subsidiary preferred stock dividends | — | — | (132 | ) | (132 | ) | — | (132 | ) | ||||||||||||||
Dividends declared on common stock | — | — | (21,108 | ) | (21,108 | ) | — | (21,108 | ) | ||||||||||||||
Proceeds from stock option exercise | 802 | — | — | 802 | — | 802 | |||||||||||||||||
Awards of common stock | (10,845 | ) | — | — | (10,845 | ) | — | (10,845 | ) | ||||||||||||||
Stock based compensation expense | 2,894 | — | — | 2,894 | — | 2,894 | |||||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | (4,472 | ) | (4,472 | ) | |||||||||||||||
Balance at March 31, 2018 | $ | 1,150,516 | $ | (105,520 | ) | $ | 638,618 | $ | 1,683,614 | $ | 65,400 | $ | 1,749,014 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Electric Operating Revenues: | |||||||
Contracts with customers | $ | 222,564 | $ | 222,063 | |||
Alternative revenue programs | 65 | 1,087 | |||||
Other electric operating revenue | 13,603 | 28,408 | |||||
Total electric operating revenues | 236,232 | 251,558 | |||||
Operating Expenses: | |||||||
Cost of energy | 70,802 | 81,317 | |||||
Administrative and general | 43,726 | 40,909 | |||||
Energy production costs | 35,350 | 31,787 | |||||
Depreciation and amortization | 36,627 | 36,016 | |||||
Transmission and distribution costs | 9,827 | 9,919 | |||||
Taxes other than income taxes | 11,608 | 11,141 | |||||
Total operating expenses | 207,940 | 211,089 | |||||
Operating income | 28,292 | 40,469 | |||||
Other Income and Deductions: | |||||||
Interest income | 2,487 | 2,816 | |||||
Gains on investment securities | 288 | 6,661 | |||||
Other income | 2,391 | 3,843 | |||||
Other (deductions) | (1,462 | ) | (4,959 | ) | |||
Net other income and deductions | 3,704 | 8,361 | |||||
Interest Charges | 20,830 | 21,012 | |||||
Earnings before Income Taxes | 11,166 | 27,818 | |||||
Income Taxes (Benefit) | (348 | ) | 7,708 | ||||
Net Earnings | 11,514 | 20,110 | |||||
(Earnings) Attributable to Valencia Non-controlling Interest | (3,677 | ) | (3,452 | ) | |||
Net Earnings Attributable to PNM | 7,837 | 16,658 | |||||
Preferred Stock Dividends Requirements | (132 | ) | (132 | ) | |||
Net Earnings Available for PNM Common Stock | $ | 7,705 | $ | 16,526 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Net Earnings | $ | 11,514 | $ | 20,110 | |||
Other Comprehensive Income: | |||||||
Unrealized Gains on Available-for-Sale Securities: | |||||||
Unrealized holding gains arising during the period, net of income tax (expense) of $(283) and $(3,030) | 832 | 4,736 | |||||
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $668 and $1,078 | (1,961 | ) | (1,685 | ) | |||
Pension Liability Adjustment: | |||||||
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(480) and $(631) | 1,411 | 987 | |||||
Total Other Comprehensive Income | 282 | 4,038 | |||||
Comprehensive Income | 11,796 | 24,148 | |||||
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (3,677 | ) | (3,452 | ) | |||
Comprehensive Income Attributable to PNM | $ | 8,119 | $ | 20,696 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Cash Flows From Operating Activities: | |||||||
Net earnings | $ | 11,514 | $ | 20,110 | |||
Adjustments to reconcile net earnings to net cash flows from operating activities: | |||||||
Depreciation and amortization | 45,165 | 44,691 | |||||
Deferred income tax expense (benefit) | (253 | ) | 7,878 | ||||
Net unrealized (gains) on commodity derivatives | (28 | ) | (1,345 | ) | |||
(Gains) on investment securities | (288 | ) | (6,661 | ) | |||
Allowance for equity funds used during construction | (2,031 | ) | (1,461 | ) | |||
Other, net | 757 | 702 | |||||
Changes in certain assets and liabilities: | |||||||
Accounts receivable and unbilled revenues | 15,100 | 17,414 | |||||
Materials, supplies, and fuel stock | (2,247 | ) | 2,083 | ||||
Other current assets | (248 | ) | 12,399 | ||||
Other assets | 3,999 | 4,399 | |||||
Accounts payable | (18,014 | ) | (2,509 | ) | |||
Accrued interest and taxes | 17,984 | 16,954 | |||||
Other current liabilities | (13,868 | ) | 2,946 | ||||
Other liabilities | (4,381 | ) | (1,325 | ) | |||
Net cash flows from operating activities | 53,161 | 116,275 | |||||
Cash Flows From Investing Activities: | |||||||
Utility plant additions | (61,720 | ) | (65,781 | ) | |||
Proceeds from sales of investment securities | 626,729 | 266,388 | |||||
Purchases of investment securities | (628,999 | ) | (267,891 | ) | |||
Other, net | 128 | 128 | |||||
Net cash flows from investing activities | (63,862 | ) | (67,156 | ) |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Cash Flows From Financing Activities: | |||||||
Revolving credit facilities borrowings (repayments), net | (39,800 | ) | (44,800 | ) | |||
Short-term borrowings (repayments) - affiliate, net | 54,600 | — | |||||
Dividends paid | (132 | ) | (132 | ) | |||
Valencia’s transactions with its owner | (4,472 | ) | (4,028 | ) | |||
Other, net | (584 | ) | (389 | ) | |||
Net cash flows from financing activities | 9,612 | (49,349 | ) | ||||
Change in Cash, Restricted Cash, and Equivalents | (1,089 | ) | (230 | ) | |||
Cash, Restricted Cash, and Equivalents at Beginning of Period | 1,108 | 1,324 | |||||
Cash, Restricted Cash, and Equivalents at End of Period | $ | 19 | $ | 1,094 | |||
Restricted Cash Included in Other Current Assets on Condensed Consolidated Balance Sheets: | |||||||
At beginning of period | $ | — | $ | 1,000 | |||
At end of period | $ | — | $ | 1,000 | |||
Supplemental Cash Flow Disclosures: | |||||||
Interest paid, net of amounts capitalized | $ | 9,560 | $ | 9,330 | |||
Income taxes paid (refunded), net | $ | — | $ | — | |||
Supplemental schedule of noncash investing activities: | |||||||
(Increase) decrease in accrued plant additions | $ | 2,682 | $ | 3,449 |
March 31, 2018 | December 31, 2017 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 19 | $ | 1,108 | |||
Accounts receivable, net of allowance for uncollectible accounts of $1,118 and $1,081 | 61,908 | 67,227 | |||||
Unbilled revenues | 33,331 | 43,869 | |||||
Other receivables | 14,573 | 14,541 | |||||
Affiliate receivables | 8,859 | 9,486 | |||||
Materials, supplies, and fuel stock | 63,105 | 60,859 | |||||
Regulatory assets | 827 | 2,139 | |||||
Commodity derivative instruments | 1,087 | 1,088 | |||||
Income taxes receivable | 3,505 | 3,410 | |||||
Other current assets | 41,607 | 39,904 | |||||
Total current assets | 228,821 | 243,631 | |||||
Other Property and Investments: | |||||||
Investment securities | 324,003 | 323,524 | |||||
Other investments | 155 | 283 | |||||
Non-utility property | 96 | 96 | |||||
Total other property and investments | 324,254 | 323,903 | |||||
Utility Plant: | |||||||
Plant in service and held for future use | 5,537,638 | 5,501,070 | |||||
Less accumulated depreciation and amortization | 2,052,380 | 2,029,534 | |||||
3,485,258 | 3,471,536 | ||||||
Construction work in progress | 214,139 | 204,079 | |||||
Nuclear fuel, net of accumulated amortization of $49,905 and $43,524 | 89,262 | 88,701 | |||||
Net utility plant | 3,788,659 | 3,764,316 | |||||
Deferred Charges and Other Assets: | |||||||
Regulatory assets | 453,912 | 459,239 | |||||
Goodwill | 51,632 | 51,632 | |||||
Commodity derivative instruments | 3,277 | 3,556 | |||||
Other deferred charges | 75,186 | 75,286 | |||||
Total deferred charges and other assets | 584,007 | 589,713 | |||||
$ | 4,925,741 | $ | 4,921,563 | ||||
March 31, 2018 | December 31, 2017 | ||||||
(In thousands, except share information) | |||||||
LIABILITIES AND STOCKHOLDER’S EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | — | $ | 39,800 | |||
Short-term debt - affiliate | 54,600 | — | |||||
Current installments of long-term debt | 200,006 | 23 | |||||
Accounts payable | 56,398 | 77,094 | |||||
Affiliate payables | 11,543 | 22,875 | |||||
Customer deposits | 11,045 | 11,028 | |||||
Accrued interest and taxes | 52,024 | 33,945 | |||||
Regulatory liabilities | 934 | 784 | |||||
Commodity derivative instruments | 1,328 | 1,182 | |||||
Dividends declared | 132 | 132 | |||||
Other current liabilities | 28,302 | 31,633 | |||||
Total current liabilities | 416,312 | 218,496 | |||||
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | 1,458,425 | 1,657,887 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes | 454,568 | 449,012 | |||||
Regulatory liabilities | 749,319 | 754,441 | |||||
Asset retirement obligations | 148,462 | 145,707 | |||||
Accrued pension liability and postretirement benefit cost | 81,756 | 86,124 | |||||
Commodity derivative instruments | 3,277 | 3,556 | |||||
Other deferred credits | 106,532 | 106,442 | |||||
Total deferred credits and liabilities | 1,543,914 | 1,545,282 | |||||
Total liabilities | 3,418,651 | 3,421,665 | |||||
Commitments and Contingencies (See 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 | |||||
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 | |||||
Accumulated other comprehensive income (loss), net of income taxes | (108,019 | ) | (97,093 | ) | |||
Retained earnings | 273,262 | 254,349 | |||||
Total PNM common stockholder’s equity | 1,430,161 | 1,422,174 | |||||
Non-controlling interest in Valencia | 65,400 | 66,195 | |||||
Total equity | 1,495,561 | 1,488,369 | |||||
$ | 4,925,741 | $ | 4,921,563 |
Attributable to PNM | |||||||||||||||||||||||
Total PNM Common Stockholder’s Equity | Non- controlling Interest in Valencia | ||||||||||||||||||||||
Common Stock | AOCI | Retained Earnings | Total Equity | ||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Balance at December 31, 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 adjusted | 1,264,918 | (108,301 | ) | 265,557 | 1,422,174 | 66,195 | 1,488,369 | ||||||||||||||||
Net earnings | — | — | 7,837 | 7,837 | 3,677 | 11,514 | |||||||||||||||||
Total other comprehensive income | — | 282 | — | 282 | — | 282 | |||||||||||||||||
Dividends declared on preferred stock | — | — | (132 | ) | (132 | ) | — | (132 | ) | ||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | (4,472 | ) | (4,472 | ) | |||||||||||||||
Balance at March 31, 2018 | $ | 1,264,918 | $ | (108,019 | ) | $ | 273,262 | $ | 1,430,161 | $ | 65,400 | $ | 1,495,561 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Electric Operating Revenues: | |||||||
Contracts with customers | $ | 80,787 | $ | 75,128 | |||
Alternative revenue programs | 859 | 3,492 | |||||
Total Electric Operating Revenues | 81,646 | 78,620 | |||||
Operating Expenses: | |||||||
Cost of energy | 21,754 | 21,487 | |||||
Administrative and general | 10,709 | 10,403 | |||||
Depreciation and amortization | 16,387 | 15,371 | |||||
Transmission and distribution costs | 7,128 | 6,558 | |||||
Taxes other than income taxes | 7,136 | 6,836 | |||||
Total operating expenses | 63,114 | 60,655 | |||||
Operating income | 18,532 | 17,965 | |||||
Other Income and Deductions: | |||||||
Other income | 754 | 822 | |||||
Other (deductions) | 331 | (90 | ) | ||||
Net other income and deductions | 1,085 | 732 | |||||
Interest Charges | 7,729 | 7,404 | |||||
Earnings before Income Taxes | 11,888 | 11,293 | |||||
Income Taxes | 2,475 | 3,689 | |||||
Net Earnings | $ | 9,413 | $ | 7,604 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Cash Flows From Operating Activities: | |||||||
Net earnings | $ | 9,413 | $ | 7,604 | |||
Adjustments to reconcile net earnings to net cash flows from operating activities: | |||||||
Depreciation and amortization | 16,836 | 15,921 | |||||
Deferred income tax expense (benefit) | (953 | ) | 2,746 | ||||
Other, net | (456 | ) | (168 | ) | |||
Changes in certain assets and liabilities: | |||||||
Accounts receivable and unbilled revenues | 3,115 | 3,138 | |||||
Materials and supplies | (729 | ) | (247 | ) | |||
Other current assets | 331 | (838 | ) | ||||
Other assets | (3,055 | ) | (2,042 | ) | |||
Accounts payable | (4,400 | ) | (788 | ) | |||
Accrued interest and taxes | (1,952 | ) | (3,991 | ) | |||
Other current liabilities | 5,874 | 134 | |||||
Other liabilities | 1,456 | 361 | |||||
Net cash flows from operating activities | 25,480 | 21,830 | |||||
Cash Flows From Investing Activities: | |||||||
Utility plant additions | (49,956 | ) | (36,345 | ) | |||
Net cash flows from investing activities | (49,956 | ) | (36,345 | ) | |||
Cash Flow From Financing Activities: | |||||||
Revolving credit facilities borrowings (repayments), net | 21,200 | 22,000 | |||||
Short-term borrowings (repayments) – affiliate, net | 2,600 | 1,700 | |||||
Dividends paid | (1,024 | ) | (9,855 | ) | |||
Net cash flows from financing activities | 22,776 | 13,845 | |||||
Change in Cash and Cash Equivalents | (1,700 | ) | (670 | ) | |||
Cash and Cash Equivalents at Beginning of Period | 1,700 | 671 | |||||
Cash and Cash Equivalents at End of Period | $ | — | $ | 1 | |||
Supplemental Cash Flow Disclosures: | |||||||
Interest paid, net of amounts capitalized | $ | 1,830 | $ | 2,584 | |||
Income taxes paid (refunded), net | $ | (8 | ) | $ | — | ||
Supplemental schedule of noncash investing activities: | |||||||
(Increase) decrease in accrued plant additions | $ | 9,868 | $ | 2,235 |
March 31, 2018 | December 31, 2017 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | — | $ | 1,700 | |||
Accounts receivable | 22,248 | 23,246 | |||||
Unbilled revenues | 8,069 | 10,186 | |||||
Other receivables | 3,062 | 2,860 | |||||
Affiliate receivables | — | 336 | |||||
Materials and supplies | 6,373 | 5,643 | |||||
Regulatory assets | 596 | 794 | |||||
Other current assets | 796 | 1,131 | |||||
Total current assets | 41,144 | 45,896 | |||||
Other Property and Investments: | |||||||
Other investments | 220 | 220 | |||||
Non-utility property | 2,240 | 2,240 | |||||
Total other property and investments | 2,460 | 2,460 | |||||
Utility Plant: | |||||||
Plant in service and plant held for future use | 1,513,724 | 1,504,778 | |||||
Less accumulated depreciation and amortization | 466,976 | 460,858 | |||||
1,046,748 | 1,043,920 | ||||||
Construction work in progress | 61,695 | 34,350 | |||||
Net utility plant | 1,108,443 | 1,078,270 | |||||
Deferred Charges and Other Assets: | |||||||
Regulatory assets | 141,486 | 141,433 | |||||
Goodwill | 226,665 | 226,665 | |||||
Other deferred charges | 6,236 | 6,046 | |||||
Total deferred charges and other assets | 374,387 | 374,144 | |||||
$ | 1,526,434 | $ | 1,500,770 |
March 31, 2018 | December 31, 2017 | ||||||
(In thousands, except share information) | |||||||
LIABILITIES AND STOCKHOLDER’S EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | 21,200 | $ | — | |||
Short-term debt – affiliate | 2,600 | — | |||||
Accounts payable | 15,544 | 29,812 | |||||
Affiliate payables | 4,635 | 667 | |||||
Accrued interest and taxes | 27,666 | 29,619 | |||||
Regulatory liabilities | 2,225 | 1,525 | |||||
Other current liabilities | 3,320 | 2,450 | |||||
Total current liabilities | 77,190 | 64,073 | |||||
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | 480,716 | 480,620 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes | 125,515 | 126,415 | |||||
Regulatory liabilities | 184,734 | 179,137 | |||||
Asset retirement obligations | 809 | 793 | |||||
Accrued pension liability and postretirement benefit cost | 7,084 | 7,879 | |||||
Other deferred credits | 7,592 | 7,448 | |||||
Total deferred credits and other liabilities | 325,734 | 321,672 | |||||
Total liabilities | 883,640 | 866,365 | |||||
Commitments and Contingencies (See Note 11) | |||||||
Common Stockholder's Equity: | |||||||
Common stock ($10 par value; 12,000,000 shares authorized; issued and outstanding 6,358 shares) | 64 | 64 | |||||
Paid-in-capital | 504,166 | 504,166 | |||||
Retained earnings | 138,564 | 130,175 | |||||
Total common stockholder’s equity | 642,794 | 634,405 | |||||
$ | 1,526,434 | $ | 1,500,770 |
Common Stock | Paid-in Capital | Retained Earnings | Total Common Stockholder’s Equity | ||||||||||||
(In thousands) | |||||||||||||||
Balance at December 31, 2017 | $ | 64 | $ | 504,166 | $ | 130,175 | $ | 634,405 | |||||||
Net earnings | — | — | 9,413 | 9,413 | |||||||||||
Dividends declared on common stock | — | — | (1,024 | ) | (1,024 | ) | |||||||||
Balance at March 31, 2018 | $ | 64 | $ | 504,166 | $ | 138,564 | $ | 642,794 |
(1) | Significant Accounting Policies and Responsibility for Financial Statements |
(2) | Segment Information |
PNM | TNMP | Corporate and Other | Consolidated | ||||||||||||
(In thousands) | |||||||||||||||
Three Months Ended March 31, 2018 | |||||||||||||||
Electric operating revenues | $ | 236,232 | $ | 81,646 | $ | — | $ | 317,878 | |||||||
Cost of energy | 70,802 | 21,754 | — | 92,556 | |||||||||||
Utility margin | 165,430 | 59,892 | — | 225,322 | |||||||||||
Other operating expenses | 100,511 | 24,973 | (5,016 | ) | 120,468 | ||||||||||
Depreciation and amortization | 36,627 | 16,387 | 5,708 | 58,722 | |||||||||||
Operating income (loss) | 28,292 | 18,532 | (692 | ) | 46,132 | ||||||||||
Interest income | 2,487 | — | 1,637 | 4,124 | |||||||||||
Other income (deductions) | 1,217 | 1,085 | 79 | 2,381 | |||||||||||
Interest charges | (20,830 | ) | (7,729 | ) | (4,496 | ) | (33,055 | ) | |||||||
Segment earnings (loss) before income taxes | 11,166 | 11,888 | (3,472 | ) | 19,582 | ||||||||||
Income taxes (benefit) | (348 | ) | 2,475 | (1,344 | ) | 783 | |||||||||
Segment earnings (loss) | 11,514 | 9,413 | (2,128 | ) | 18,799 | ||||||||||
Valencia non-controlling interest | (3,677 | ) | — | — | (3,677 | ) | |||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | |||||||||
Segment earnings (loss) attributable to PNMR | $ | 7,705 | $ | 9,413 | $ | (2,128 | ) | $ | 14,990 | ||||||
At March 31, 2018: | |||||||||||||||
Total Assets | $ | 4,925,741 | $ | 1,526,434 | $ | 224,218 | $ | 6,676,393 | |||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 |
PNM | TNMP | Corporate and Other | Consolidated | ||||||||||||
(In thousands) | |||||||||||||||
Three Months Ended March 31, 2017 | |||||||||||||||
Electric operating revenues | $ | 251,558 | $ | 78,620 | $ | — | $ | 330,178 | |||||||
Cost of energy | 81,317 | 21,487 | — | 102,804 | |||||||||||
Utility margin | 170,241 | 57,133 | — | 227,374 | |||||||||||
Other operating expenses | 93,756 | 23,797 | (4,660 | ) | 112,893 | ||||||||||
Depreciation and amortization | 36,016 | 15,371 | 4,996 | 56,383 | |||||||||||
Operating income (loss) | 40,469 | 17,965 | (336 | ) | 58,098 | ||||||||||
Interest income | 2,816 | — | 2,065 | 4,881 | |||||||||||
Other income (deductions) | 5,545 | 732 | (335 | ) | 5,942 | ||||||||||
Interest charges | (21,012 | ) | (7,404 | ) | (3,284 | ) | (31,700 | ) | |||||||
Segment earnings (loss) before income taxes | 27,818 | 11,293 | (1,890 | ) | 37,221 | ||||||||||
Income taxes (benefit) | 7,708 | 3,689 | (622 | ) | 10,775 | ||||||||||
Segment earnings (loss) | 20,110 | 7,604 | (1,268 | ) | 26,446 | ||||||||||
Valencia non-controlling interest | (3,452 | ) | — | — | (3,452 | ) | |||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | |||||||||
Segment earnings (loss) attributable to PNMR | $ | 16,526 | $ | 7,604 | $ | (1,268 | ) | $ | 22,862 | ||||||
At March 31, 2017: | |||||||||||||||
Total Assets | $ | 4,870,201 | $ | 1,396,055 | $ | 211,423 | $ | 6,477,679 | |||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 |
(3) | Accumulated Other Comprehensive Income (Loss) |
Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||||
PNM | PNMR | ||||||||||||||||||
Unrealized | Fair Value | ||||||||||||||||||
Gains on | Adjustment | ||||||||||||||||||
Available-for- | Pension | for Cash | |||||||||||||||||
Sale | Liability | Flow | |||||||||||||||||
Securities | Adjustment | Total | Hedges | Total | |||||||||||||||
(In thousands) | |||||||||||||||||||
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 adjusted | 1,961 | (110,262 | ) | (108,301 | ) | 1,153 | (107,148 | ) | |||||||||||
Amounts reclassified from AOCI (pre-tax) | (2,629 | ) | 1,891 | (738 | ) | (53 | ) | (791 | ) | ||||||||||
Income tax impact of amounts reclassified | 668 | (480 | ) | 188 | 13 | 201 | |||||||||||||
Other OCI changes (pre-tax) | 1,115 | — | 1,115 | 1,858 | 2,973 | ||||||||||||||
Income tax impact of other OCI changes | (283 | ) | — | (283 | ) | (472 | ) | (755 | ) | ||||||||||
Net after-tax change | (1,129 | ) | 1,411 | 282 | 1,346 | 1,628 | |||||||||||||
Balance at March 31, 2018 | $ | 832 | $ | (108,851 | ) | $ | (108,019 | ) | $ | 2,499 | $ | (105,520 | ) |
Balance at December 31, 2016 | $ | 4,320 | $ | (96,748 | ) | $ | (92,428 | ) | $ | (23 | ) | $ | (92,451 | ) | |||||
Amounts reclassified from AOCI (pre-tax) | (2,763 | ) | 1,618 | (1,145 | ) | 112 | (1,033 | ) | |||||||||||
Income tax impact of amounts reclassified | 1,078 | (631 | ) | 447 | (44 | ) | 403 | ||||||||||||
Other OCI changes (pre-tax) | 7,766 | — | 7,766 | (185 | ) | 7,581 | |||||||||||||
Income tax impact of other OCI changes | (3,030 | ) | — | (3,030 | ) | 72 | (2,958 | ) | |||||||||||
Net after-tax change | 3,051 | 987 | 4,038 | (45 | ) | 3,993 | |||||||||||||
Balance at March 31, 2017 | $ | 7,371 | $ | (95,761 | ) | $ | (88,390 | ) | $ | (68 | ) | $ | (88,458 | ) |
(4) | Earnings Per Share |
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
(In thousands, except per share amounts) | |||||||
Net Earnings Attributable to PNMR | $ | 14,990 | $ | 22,862 | |||
Average Number of Common Shares: | |||||||
Outstanding during period | 79,654 | 79,654 | |||||
Vested awards of restricted stock | 205 | 112 | |||||
Average Shares – Basic | 79,859 | 79,766 | |||||
Dilutive Effect of Common Stock Equivalents: | |||||||
Stock options and restricted stock | 154 | 346 | |||||
Average Shares – Diluted | 80,013 | 80,112 | |||||
Net Earnings Per Share of Common Stock: | |||||||
Basic | $ | 0.19 | $ | 0.29 | |||
Diluted | $ | 0.19 | $ | 0.29 |
(5) | Electric Operating Revenues |
PNM | TNMP | Consolidated | ||||||||||
(In thousands) | ||||||||||||
Electric Operating Revenues: | ||||||||||||
Contracts with customers: | ||||||||||||
Retail electric revenue | ||||||||||||
Residential | $ | 97,169 | $ | 29,266 | $ | 126,435 | ||||||
Commercial | 82,849 | 27,152 | 110,001 | |||||||||
Industrial | 13,459 | 4,305 | 17,764 | |||||||||
Public authority | 4,635 | 1,416 | 6,051 | |||||||||
Economy energy service | 7,288 | — | 7,288 | |||||||||
Transmission | 12,482 | 16,508 | 28,990 | |||||||||
Miscellaneous | 4,682 | 2,140 | 6,822 | |||||||||
Total revenues from contracts with customers | 222,564 | 80,787 | 303,351 | |||||||||
Alternative revenue programs | 65 | 859 | 924 | |||||||||
Other electric operating revenues | 13,603 | — | 13,603 | |||||||||
Total Electric Operating Revenues | $ | 236,232 | $ | 81,646 | $ | 317,878 |
PNM | TNMP | Consolidated | ||||||||||
(In thousands) | ||||||||||||
Balance at December 31, 2017 | $ | 349 | $ | — | $ | 349 | ||||||
Consideration received in advance of service to be provided | 3,983 | 1,512 | 5,495 | |||||||||
Deferred revenue earned | (1,099 | ) | (378 | ) | (1,477 | ) | ||||||
Balance at March 31, 2018 | $ | 3,233 | $ | 1,134 | $ | 4,367 |
(6) | Variable Interest Entities |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Operating revenues | $ | 4,768 | $ | 4,927 | |||
Operating expenses | (1,091 | ) | (1,475 | ) | |||
Earnings attributable to non-controlling interest | $ | 3,677 | $ | 3,452 |
March 31, | December 31, | ||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Current assets | $ | 2,981 | $ | 2,688 | |||
Net property, plant, and equipment | 63,400 | 64,109 | |||||
Total assets | 66,381 | 66,797 | |||||
Current liabilities | 981 | 602 | |||||
Owners’ equity – non-controlling interest | $ | 65,400 | $ | 66,195 |
(7) | Fair Value of Derivative and Other Financial Instruments |
Economic Hedges | |||||||
March 31, 2018 | December 31, 2017 | ||||||
(In thousands) | |||||||
Current assets | $ | 1,087 | $ | 1,088 | |||
Deferred charges | 3,277 | 3,556 | |||||
4,364 | 4,644 | ||||||
Current liabilities | (1,328 | ) | (1,182 | ) | |||
Long-term liabilities | (3,277 | ) | (3,556 | ) | |||
(4,605 | ) | (4,738 | ) | ||||
Net | $ | (241 | ) | $ | (94 | ) |
Economic Hedges | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Electric operating revenues | $ | (10 | ) | $ | 3,341 | ||
Cost of energy | 12 | 11 | |||||
Total gain | $ | 2 | $ | 3,352 |
Economic Hedges | ||||||
MMBTU | MWh | |||||
March 31, 2018 | 405,000 | (40,800 | ) | |||
December 31, 2017 | 100,000 | — |
Three Months Ended March 31, 2018 | ||||
(In thousands) | ||||
Equity securities: | ||||
Net gains from equity securities sold | $ | 2,828 | ||
Net gains from equity securities still held | 136 | |||
Total net gains on equity securities | 2,964 | |||
Available-for-sale debt securities: | ||||
Net gains (losses) on debt securities | (2,676 | ) | ||
Net gains on investment securities | $ | 288 |
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Proceeds from sales | $ | 626,729 | $ | 266,388 | |||
Gross realized gains | $ | 6,021 | $ | 8,645 | |||
Gross realized (losses) | $ | (4,677 | ) | $ | (3,085 | ) |
Fair Value | |||||||
Available-for-Sale | Held-to-Maturity | ||||||
PNMR and PNM | PNMR | ||||||
(In thousands) | |||||||
Within 1 year | $ | 8,562 | $ | — | |||
After 1 year through 5 years | 53,094 | 57,486 | |||||
After 5 years through 10 years | 66,603 | — | |||||
After 10 years through 15 years | 9,735 | — | |||||
After 15 years through 20 years | 10,061 | — | |||||
After 20 years | 36,263 | — | |||||
$ | 184,318 | $ | 57,486 |
GAAP Fair Value Hierarchy | |||||||||||||||||||
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) | |||||||||||||||||||
March 31, 2018 | |||||||||||||||||||
Cash and cash equivalents | $ | 22,810 | $ | 22,810 | $ | — | $ | — | |||||||||||
Equity securities: | |||||||||||||||||||
Corporate stocks, common | 35,185 | 35,185 | — | — | |||||||||||||||
Corporate stocks, preferred | 6,714 | 865 | 5,849 | — | |||||||||||||||
Mutual funds and other | 74,976 | 74,976 | — | — | |||||||||||||||
Available-for-sale debt securities: | |||||||||||||||||||
U.S. Government | 23,829 | 23,829 | — | — | $ | 271 | |||||||||||||
International Government | 9,894 | — | 9,894 | — | 61 | ||||||||||||||
Municipals | 35,782 | — | 35,782 | — | 103 | ||||||||||||||
Corporate and other | 114,813 | — | 112,462 | 2,351 | 680 | ||||||||||||||
$ | 324,003 | $ | 157,665 | $ | 163,987 | $ | 2,351 | $ | 1,115 | ||||||||||
Commodity derivative assets | $ | 4,364 | $ | — | $ | 4,364 | $ | — | |||||||||||
Commodity derivative liabilities | (4,605 | ) | — | (4,605 | ) | — | |||||||||||||
Net | $ | (241 | ) | $ | — | $ | (241 | ) | $ | — | |||||||||
December 31, 2017 | |||||||||||||||||||
Available-for-sale securities | |||||||||||||||||||
Cash and cash equivalents | $ | 52,636 | $ | 52,636 | $ | — | $ | — | |||||||||||
Equity securities: | |||||||||||||||||||
Domestic value | 40,032 | 40,032 | — | — | $ | 4,011 | |||||||||||||
Domestic growth | 35,456 | 35,456 | — | — | 3,995 | ||||||||||||||
International and other | 45,867 | 42,332 | 3,535 | — | 6,810 | ||||||||||||||
Fixed income securities: | |||||||||||||||||||
U.S. Government | 34,317 | 33,645 | 672 | — | 273 | ||||||||||||||
Municipals | 48,076 | — | 48,076 | — | 1,225 | ||||||||||||||
Corporate and other | 67,140 | — | 67,140 | — | 1,714 | ||||||||||||||
$ | 323,524 | $ | 204,101 | $ | 119,423 | $ | — | $ | 18,028 | ||||||||||
Commodity derivative assets | $ | 4,644 | $ | — | $ | 4,644 | $ | — | |||||||||||
Commodity derivative liabilities | (4,738 | ) | — | (4,738 | ) | — | |||||||||||||
Net | $ | (94 | ) | $ | — | $ | (94 | ) | $ | — |
Corporate Debt | |||
(In thousands) | |||
Balance at December 31, 2017 | $ | — | |
Actual return on assets sold during the period | (3 | ) | |
Actual return on assets still held at period end | (11 | ) | |
Purchases | 2,724 | ||
Sales | (359 | ) | |
Balances at March 31, 2018 | $ | 2,351 |
GAAP Fair Value Hierarchy | |||||||||||||||||||
Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||||
March 31, 2018 | (In thousands) | ||||||||||||||||||
PNMR | |||||||||||||||||||
Long-term debt | $ | 2,581,549 | $ | 2,661,283 | $ | — | $ | 2,661,283 | $ | — | |||||||||
Westmoreland Loan | $ | 50,991 | $ | 57,486 | $ | — | $ | — | $ | 57,486 | |||||||||
Other investments | $ | 375 | $ | 375 | $ | 375 | $ | — | $ | — | |||||||||
PNM | |||||||||||||||||||
Long-term debt | $ | 1,658,431 | $ | 1,703,098 | $ | — | $ | 1,703,098 | $ | — | |||||||||
Other investments | $ | 155 | $ | 155 | $ | 155 | $ | — | $ | — | |||||||||
TNMP | |||||||||||||||||||
Long-term debt | $ | 480,716 | $ | 513,690 | $ | — | $ | 513,690 | $ | — | |||||||||
Other investments | $ | 220 | $ | 220 | $ | 220 | $ | — | $ | — | |||||||||
December 31, 2017 | |||||||||||||||||||
PNMR | |||||||||||||||||||
Long-term debt | $ | 2,437,645 | $ | 2,554,836 | $ | — | $ | 2,554,836 | $ | — | |||||||||
Westmoreland Loan | $ | 56,640 | $ | 66,588 | $ | — | $ | — | $ | 66,588 | |||||||||
Other investments | $ | 503 | $ | 503 | $ | 503 | $ | — | $ | — | |||||||||
PNM | |||||||||||||||||||
Long-term debt | $ | 1,657,910 | $ | 1,727,135 | $ | — | $ | 1,727,135 | $ | — | |||||||||
Other investments | $ | 283 | $ | 283 | $ | 283 | $ | — | $ | — | |||||||||
TNMP | |||||||||||||||||||
Long-term debt | $ | 480,620 | $ | 527,563 | $ | — | $ | 527,563 | $ | — | |||||||||
Other investments | $ | 220 | $ | 220 | $ | 220 | $ | — | $ | — |
(8) | Stock-Based Compensation |
Three Months Ended March 31, | ||||||||
Restricted Shares and Performance Based Shares | 2018 | 2017 | ||||||
Expected quarterly dividends per share | $ | 0.2650 | $ | 0.2425 | ||||
Risk-free interest rate | 2.39 | % | 1.58 | % | ||||
Market-Based Shares | ||||||||
Dividend yield | 2.96 | % | 2.67 | % | ||||
Expected volatility | 19.12 | % | 20.80 | % | ||||
Risk-free interest rate | 2.36 | % | 1.54 | % |
Restricted Stock | Stock Options | ||||||||||||
Shares | Weighted- Average Grant Date Fair Value | Shares | Weighted- Average Exercise Price | ||||||||||
Outstanding at December 31, 2017 | 189,045 | $ | 31.11 | 193,441 | $ | 9.98 | |||||||
Granted | 204,654 | $ | 29.03 | — | $ | — | |||||||
Exercised | (201,162 | ) | $ | 27.68 | (97,941 | ) | $ | 8.19 | |||||
Forfeited | (3,562 | ) | $ | 30.58 | — | $ | — | ||||||
Expired | — | $ | — | — | $ | — | |||||||
Outstanding at March 31, 2018 | 188,975 | $ | 32.52 | 95,500 | $ | 11.81 |
Three Months Ended March 31, | ||||||||
Restricted Stock | 2018 | 2017 | ||||||
Weighted-average grant date fair value | $ | 29.03 | $ | 22.12 | ||||
Total fair value of restricted shares that vested (in thousands) | $ | 7,162 | $ | 5,024 | ||||
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) | $ | 2,711 | $ | 945 |
(9) | Financing |
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 |
March 31, | December 31, | |||||||
Short-term Debt | 2018 | 2017 | ||||||
(In thousands) | ||||||||
PNM: | ||||||||
PNM Revolving Credit Facility | $ | — | $ | 39,800 | ||||
PNM 2017 New Mexico Credit Facility | — | — | ||||||
— | 39,800 | |||||||
TNMP Revolving Credit Facility | 21,200 | — | ||||||
PNMR: | ||||||||
PNMR Revolving Credit Facility | 96,000 | 165,600 | ||||||
PNMR 2016 One-Year Term Loan (as extended) | 100,000 | 100,000 | ||||||
PNMR Development Revolving Credit Facility | 21,500 | — | ||||||
$ | 238,700 | $ | 305,400 |
(10) | Pension and Other Postretirement Benefit Plans |
Three Months Ended March 31, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2018 | 2017 | 2018 | 2017 | 2018 | 2017 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 21 | $ | 24 | $ | — | $ | — | |||||||||||
Interest cost | 6,068 | 6,727 | 860 | 1,006 | 155 | 174 | |||||||||||||||||
Expected return on plan assets | (8,672 | ) | (8,451 | ) | (1,353 | ) | (1,308 | ) | — | — | |||||||||||||
Amortization of net (gain) loss | 4,087 | 4,001 | 588 | 921 | 90 | 78 | |||||||||||||||||
Amortization of prior service cost | (241 | ) | (241 | ) | (416 | ) | (416 | ) | — | — | |||||||||||||
Net periodic benefit cost | $ | 1,242 | $ | 2,036 | $ | (300 | ) | $ | 227 | $ | 245 | $ | 252 |
Three Months Ended March 31, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2018 | 2017 | 2018 | 2017 | 2018 | 2017 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 33 | $ | 36 | $ | — | $ | — | |||||||||||
Interest cost | 656 | 722 | 119 | 139 | 7 | 8 | |||||||||||||||||
Expected return on plan assets | (991 | ) | (945 | ) | (135 | ) | (114 | ) | — | — | |||||||||||||
Amortization of net (gain) loss | 272 | 231 | (56 | ) | (20 | ) | 4 | 2 | |||||||||||||||
Amortization of prior service cost | — | — | — | — | — | — | |||||||||||||||||
Net Periodic Benefit Cost | $ | (63 | ) | $ | 8 | $ | (39 | ) | $ | 41 | $ | 11 | $ | 10 |
(11) | Commitments and Contingencies |
• | PNM was granted a CCN to acquire an additional 132 MW in SJGS Unit 4 effective January 1, 2018 |
• | PNM was granted a CCN for 134 MW of PVNGS Unit 3 as a jurisdictional resource to serve New Mexico customers beginning January 1, 2018 |
• | 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 in a NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022; all parties to the stipulation agree to support this case being decided within six months (see Other SJGS Matters below and Note 12) |
• | PNM was authorized to acquire 65 MW of SJGS Unit 4 as merchant plant |
(12) | Regulatory and Rate Matters |
• | 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 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), 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 13) and related property taxes, which were $1.5 million per year at that time; 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 |
• | 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 |
• | Allowing 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 |
• | 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 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 |
• | 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 $75.3 million, after considering the losses recorded in 2016 and 2017 |
• | 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 $39.1 million, after considering the losses recorded in 2016 and 2017 |
• | The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $49.4 million, after considering the losses recorded in 2016 and 2017 |
• | 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 |
• | 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 PNM’s investment in SCRs at Four Corners with a debt-only return |
• | An agreement to not implement non-fuel base rate changes, other than changes related to PNM’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 14) to the extent attributable to PNM’s retail operations |
• | PNM would withdraw its proposal for a “lost contribution to fixed cost” mechanism with the issue to be addressed in a future docket |
• | PNM would perform a cost benefit analysis in its 2020 IRP of the impact of a possible early exit from Four Corners in 2024 and 2028 |
• | 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 |
• | 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 rendered, beginning February 1, 2018 and of the second for services rendered beginning January 1, 2019 |
• | 107 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 1.5 MW of PNM-owned solar PV facilities to supply the energy sold under PNM’s voluntary renewable energy tariff |
• | A PPA through 2044 for the output of New Mexico Wind, having a 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 86.2 MW at March 31, 2018, owned by customers or third parties from whom PNM purchases any net excess output and RECs |
• | Solar and wind RECs as needed to meet the RPS requirements |
• | 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 |
• | 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 |
• | Casa Mesa Wind, LLC, a subsidiary of NextEra Energy Resources, LLC., which is expected to be located near House, New Mexico, have a total capacity of 50 MW, and 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 subsidiary of NextEra Energy Resources, LLC., which is expected to be located west of Albuquerque, New Mexico, have a total capacity of 50 MW, and be operational in December 2021 |
Effective Date | Approved Increase in Rate Base | Annual Increase in Revenue | ||||||
(In millions) | ||||||||
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 | ||||||
March 27, 2018 | 32.0 | 0.6 |
(13) | Lease Commitments |
(14) | Income Taxes |
(15) | Related Party Transactions |
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
(In thousands) | |||||||
Services billings: | |||||||
PNMR to PNM | $ | 23,679 | $ | 24,402 | |||
PNMR to TNMP | 8,365 | 8,137 | |||||
PNM to TNMP | 86 | 85 | |||||
TNMP to PNMR | 35 | 35 | |||||
PNMR to NMRD | 78 | — | |||||
Renewable energy purchases: | |||||||
PNM from NMRD | 370 | — | |||||
Interest billings: | |||||||
PNMR to PNM | 62 | — | |||||
PNM to PNMR | 66 | 43 | |||||
PNMR to TNMP | 8 | 31 | |||||
Income tax sharing payments: | |||||||
PNMR to PNM | — | — | |||||
PNMR to TNMP | — | — | |||||
TNMP to PNMR | — | — |
• | Earning authorized returns on regulated businesses |
• | Delivering above industry-average earnings and dividend growth |
• | Maintaining solid investment grade credit ratings |
• | Maintaining strong employee safety, plant performance, and system reliability |
• | Delivering a superior customer experience |
• | Demonstrating environmental stewardship in business operations, including reducing CO2 emissions |
• | Supporting the communities in their service territories |
• | 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 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 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); 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 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 |
• | 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 |
• | 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 |
• | 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 PNM’s investment in SCRs at Four Corners with a debt-only return |
• | An agreement to not implement non-fuel base rate changes, other than changes related to PNM’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 would perform a cost benefit analysis in its 2020 IRP of the impact of a possible early exit from Four Corners in 2024 and 2028 |
Approval Date | Percent Increase | ||
February 2012 | 16 | % | |
February 2013 | 14 | % | |
December 2013 | 12 | % | |
December 2014 | 8 | % | |
December 2015 | 10 | % | |
December 2016 | 10 | % | |
December 2017 | 9 | % |
• | 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 |
• | Developing strategies to provide reliable and affordable power, while transforming PNM’s generation resources to a cleaner energy portfolio by reducing CO2 emissions |
• | Preparing PNM’s system to meet New Mexico’s increasing renewable energy resources as cost-effectively as possible |
• | Increasing energy efficiency participation |
• | PNM was granted a CCN to acquire an additional 132 MW in SJGS Unit 4 effective January 1, 2018 |
• | PNM was granted a CCN for 134 MW of PVNGS Unit 3 as a jurisdictional resource to serve New Mexico customers beginning January 1, 2018 |
• | PNM was authorized to acquire 65 MW of SJGS Unit 4 as merchant utility plant |
• | No later than December 31, 2018, and before entering into a binding coal supply agreement for SJGS, PNM will make a NMPRC filing to determine the extent that SJGS should continue serving PNM’s customers’ needs after mid-2022 |
Three Months Ended March 31, | |||||||||||
2018 | 2017 | Change | |||||||||
(In millions, except per share amounts) | |||||||||||
Net earnings attributable to PNMR | $ | 15.0 | $ | 22.9 | $ | (7.9 | ) | ||||
Average diluted common and common equivalent shares | 80.0 | 80.1 | (0.1 | ) | |||||||
Net earnings attributable to PNMR per diluted share | $ | 0.19 | $ | 0.29 | $ | (0.10 | ) |
Three Months Ended | |||
March 31, 2018 | |||
(In millions) | |||
PNM | $ | (8.8 | ) |
TNMP | 1.8 | ||
Corporate and Other | (0.8 | ) | |
Net change | $ | (7.9 | ) |
Three Months Ended March 31, | |||||||||||
2018 | 2017 | Change | |||||||||
(In millions) | |||||||||||
Electric operating revenues | $ | 236.2 | $ | 251.6 | $ | (15.4 | ) | ||||
Cost of energy | 70.8 | 81.3 | (10.5 | ) | |||||||
Utility margin | 165.4 | 170.2 | (4.8 | ) | |||||||
Operating expenses | 100.5 | 93.8 | 6.7 | ||||||||
Depreciation and amortization | 36.6 | 36.0 | 0.6 | ||||||||
Operating income | 28.3 | 40.5 | (12.2 | ) | |||||||
Other income (deductions) | 3.7 | 8.4 | (4.7 | ) | |||||||
Interest charges | (20.8 | ) | (21.0 | ) | 0.2 | ||||||
Segment earnings before income taxes | 11.2 | 27.8 | (16.6 | ) | |||||||
Income (taxes) benefit | 0.3 | (7.7 | ) | 8.1 | |||||||
Valencia non-controlling interest | (3.7 | ) | (3.5 | ) | (0.2 | ) | |||||
Preferred stock dividend requirements | (0.1 | ) | (0.1 | ) | — | ||||||
Segment earnings | $ | 7.7 | $ | 16.5 | $ | (8.8 | ) |
Three Months Ended March 31, | ||||||||
Percentage | ||||||||
2018 | 2017 | Change | ||||||
(Gigawatt hours, except customers) | ||||||||
Residential | 751.7 | 749.5 | 0.3 | % | ||||
Commercial | 834.4 | 826.6 | 0.9 | |||||
Industrial | 205.7 | 207.9 | (1.1 | ) | ||||
Public authority | 50.3 | 53.3 | (5.6 | ) | ||||
Economy energy service (1) | 170.7 | 186.8 | (8.6 | ) | ||||
Firm-requirements wholesale (2) | — | 21.6 | (100.0 | ) | ||||
Other sales for resale (3) | 681.0 | 1,085.4 | (37.3 | ) | ||||
2,693.8 | 3,131.1 | (14.0 | )% | |||||
Average retail customers (thousands) | 524.7 | 520.9 | 0.7 | % |
Three Months Ended March 31, 2018 | |||||
Change | |||||
Utility margin: | (In millions) | ||||
Rate relief – Additional revenue due to rate increase approved by the NMPRC effective February 1, 2018 (Note 12) | $ | 0.5 | |||
Retail Customer usage/load – Weather normalized KWh sales decreased 0.9% due to decreased sales in residential, industrial, and other customers | (1.6 | ) | |||
Weather – Colder weather in 2018; heating degree days were 19.0% higher | 2.1 | ||||
Transmission – The addition of new customers and higher revenues under formula transmission rates | 2.8 | ||||
Wholesale contracts – Loss of NEC as a wholesale generation customer | (0.3 | ) | |||
Unregulated margin – Loss of PVNGS Unit 3 wholesale power sales | (6.3 | ) | |||
Third party transmission cost – Transmission of power from PVNGS Unit 3 to serve New Mexico retail customers | (1.9 | ) | |||
Rate riders – Includes renewable energy and energy efficiency riders, which are partially offset in operating expenses, depreciation and amortization, and interest charges | 0.7 | ||||
Net unrealized economic hedges – Primarily related to 2017 hedges of PVNGS Unit 3 power sales and sales to NEC | (1.3 | ) | |||
Other | 0.5 | ||||
Net Change | $ | (4.8 | ) |
Three Months Ended March 31, 2018 | |||||
Change | |||||
Operating expenses: | (In millions) | ||||
Higher plant maintenance costs at SJGS, Four Corners, and gas-fired plants | $ | 5.1 | |||
Increased costs associated with additional 132 MW of SJGS Unit 4 and accelerated recovery of SNCRs on SJGS Units 1 and 4 | 3.3 | ||||
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 | 0.8 | ||||
Higher employee medical expenses due to unfavorable claims experience | 0.7 | ||||
Higher allocated corporate depreciation, primarily related to computer software | 0.5 | ||||
Lower capitalized administrative and general expenses due to lower construction spending in 2018 | 0.4 | ||||
Cost savings realized from the retirement of SJGS Units 2 and 3 | (5.2 | ) | |||
2017 training costs associated with new software implementation | (0.8 | ) | |||
Other | 0.5 | ||||
Net Change | $ | 6.7 |
Three Months Ended March 31, 2018 | |||||
Change | |||||
Depreciation and amortization: | (In millions) | ||||
Increased utility plant in service | $ | 2.2 | |||
Lower depreciation resulting from the retirement of SJGS Units 2 and 3, partially offset by amortization of the associated regulatory asset (Note 11) | (1.6 | ) | |||
Net Change | $ | 0.6 |
Other income (deductions): | |||||
Lower gains on investment securities in the NDT and coal mine reclamation trusts | $ | (6.4 | ) | ||
Higher equity AFUDC | 0.6 | ||||
2017 interest income from third-party transmission service provider due to FERC ruling | (1.0 | ) | |||
Lower non-service components of pension and OPEB expense | 1.3 | ||||
Higher interest income and lower trust expenses related to investment securities in the NDT and coal mine reclamation trusts | 0.8 | ||||
Net Change | $ | (4.7 | ) |
Interest charges: | |||||
Higher debt AFUDC | $ | 0.4 | |||
Other | (0.2 | ) | |||
Net Change | $ | 0.2 |
Income taxes: | |||||
Decrease due to reduction in corporate income tax rate and lower segment earnings before income taxes | $ | (7.6 | ) | ||
Amortization of excess deferred income taxes, as ordered by the NMPRC in PNM’s NM 2016 Rate Case | (1.2 | ) | |||
Increase due to lower excess tax benefits related to stock compensation awards (Note 8) | 0.4 | ||||
Other | 0.3 | ||||
Net Change | $ | (8.1 | ) |
Three Months Ended March 31, | |||||||||||
2018 | 2017 | Change | |||||||||
(In millions) | |||||||||||
Electric operating revenues | $ | 81.6 | $ | 78.6 | $ | 3.0 | |||||
Cost of energy | 21.8 | 21.5 | 0.3 | ||||||||
Utility margin | 59.9 | 57.1 | 2.8 | ||||||||
Operating expenses | 25.0 | 23.8 | 1.2 | ||||||||
Depreciation and amortization | 16.4 | 15.4 | 1.0 | ||||||||
Operating income | 18.5 | 18.0 | 0.5 | ||||||||
Other income (deductions) | 1.1 | 0.7 | 0.4 | ||||||||
Interest charges | (7.7 | ) | (7.4 | ) | (0.3 | ) | |||||
Segment earnings before income taxes | 11.9 | 11.3 | 0.6 | ||||||||
Income (taxes) | (2.5 | ) | (3.7 | ) | 1.2 | ||||||
Segment earnings | $ | 9.4 | $ | 7.6 | $ | 1.8 |
Three Months Ended March 31, | ||||||||
Percentage | ||||||||
2018 | 2017 | Change | ||||||
Volumetric load (1) (GWh) | ||||||||
Residential | 656.8 | 577.0 | 13.8 | % | ||||
Commercial and other | 8.0 | 9.2 | (13.0 | ) | ||||
Total volumetric load | 664.8 | 586.2 | 13.4 | % | ||||
Demand-based load (2) (MW) | 4,310.2 | 3,871.7 | 11.3 | % | ||||
Average retail consumers (thousands) (3) | 250.1 | 246.8 | 1.3 | % |
Three Months Ended March 31, 2018 | |||||
Change | |||||
Utility margin: | (In millions) | ||||
Rate relief – Transmission cost of service rate increases in March 2017, September 2017, and March 2018 | $ | 1.7 | |||
Retail customer usage/load – Weather normalized KWh sales increased 3.8%; the average number of retail consumers increased 1.3% | 0.4 | ||||
Demand based customer usage/load – Higher demand-based revenues for large commercial and industrial retail consumers; billed demand, excluding retail transmission customers, increased 5.4% | 0.9 | ||||
Weather – Colder weather in 2018; heating degree days were 72.2% higher in 2018 | 1.3 | ||||
Revenue subject to refund – Amounts deferred as regulatory liability for the impact of the reduction in the federal corporate income tax rate (Note 12) | (1.5 | ) | |||
Net Change | $ | 2.8 |
Three Months Ended March 31, 2018 | |||||
Change | |||||
Operating expenses: | (In millions) | ||||
Higher employee related expenses | $ | 0.3 | |||
Higher outside consulting costs, including vegetation management | 0.4 | ||||
Training costs associated with new software implementation in 2017 | (0.2 | ) | |||
Higher costs associated with rate riders, primarily the AMS surcharge | 0.4 | ||||
Higher property taxes due to increased utility plant in service | 0.4 | ||||
Other | (0.1 | ) | |||
Net Change | $ | 1.2 |
Depreciation and amortization: | |||||
Primarily due to increased utility plant in service | $ | 1.0 |
Other income (deductions): | |||||
Higher equity AFUDC | $ | 0.3 | |||
Other | 0.1 | ||||
Net Change | $ | 0.4 |
Interest charges: | |||||
Increase due to issuance of $60.0 million of long-term debt in August 2017 | $ | (0.5 | ) | ||
Higher debt AFUDC | 0.2 | ||||
Net Change | $ | (0.3 | ) |
Three Months Ended March 31, 2018 | |||||
Change | |||||
Income taxes: | (In millions) | ||||
Decrease due to reduction in corporate income tax rate, partially offset by tax on higher segment earnings | $ | 1.5 | |||
Increase due to lower excess tax benefits related to stock compensation awards (Note 8) | (0.2 | ) | |||
Other | (0.1 | ) | |||
Net Change | $ | 1.2 |
Three Months Ended March 31, | |||||||||||
2018 | 2017 | Change | |||||||||
(In millions) | |||||||||||
Total revenues | $ | — | $ | — | $ | — | |||||
Cost of energy | — | — | — | ||||||||
Utility margin | — | — | — | ||||||||
Operating expenses | (5.0 | ) | (4.7 | ) | (0.3 | ) | |||||
Depreciation and amortization | 5.7 | 5.0 | 0.7 | ||||||||
Operating income (loss) | (0.7 | ) | (0.3 | ) | (0.4 | ) | |||||
Other income (deductions) | 1.7 | 1.7 | — | ||||||||
Interest charges | (4.5 | ) | (3.3 | ) | (1.2 | ) | |||||
Segment earnings (loss) before income taxes | (3.5 | ) | (1.9 | ) | (1.6 | ) | |||||
Income (taxes) benefit | 1.3 | 0.6 | 0.7 | ||||||||
Segment earnings (loss) | $ | (2.1 | ) | $ | (1.3 | ) | $ | (0.8 | ) |
Three Months Ended March 31, 2018 | |||||
Change | |||||
Other income (deductions): | (In millions) | ||||
Decrease in interest income on the Westmoreland Loan (Note 11) | $ | (0.4 | ) | ||
Other | 0.4 | ||||
Net Change | $ | — |
Three Months Ended March 31, 2018 | |||||
Change | |||||
Interest charges: | (In millions) | ||||
Higher short term borrowings and interest rates | $ | (0.8 | ) | ||
Issuance of $300.0 million of PNMR 2018 SUNs in March 2018 (Note 9) | (0.8 | ) | |||
Decrease in interest expense on the BTMU Loan Agreement (Note 9) | 0.4 | ||||
Net Change | $ | (1.2 | ) |
Income taxes: | |||||
Decrease due to reduction in corporate income tax rate and lower segment earnings before income taxes | $ | 0.1 | |||
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 | 0.7 | ||||
Other | (0.2 | ) | |||
Net Change | $ | 0.7 |
Three Months Ended March 31, | |||||||||||
2018 | 2017 | Change | |||||||||
(In millions) | |||||||||||
Net cash flows from: | |||||||||||
Operating activities | $ | 78.9 | $ | 131.6 | $ | (52.7 | ) | ||||
Investing activities | (119.2 | ) | (106.6 | ) | (12.6 | ) | |||||
Financing activities | 40.1 | (27.2 | ) | 67.3 | |||||||
Net change in cash and cash equivalents | $ | (0.2 | ) | $ | (2.2 | ) | $ | 2.0 |
Three Months Ended March 31, | |||||||||||
2018 | 2017 | Change | |||||||||
Cash (Outflows) for Utility Plant Additions | (In millions) | ||||||||||
PNM: | |||||||||||
Generation | $ | (18.0 | ) | $ | (16.4 | ) | $ | (1.6 | ) | ||
Transmission and distribution | (33.0 | ) | (34.3 | ) | 1.3 | ||||||
Four Corners SCRs | (3.8 | ) | (8.2 | ) | 4.4 | ||||||
Nuclear fuel | (6.9 | ) | (6.9 | ) | — | ||||||
(61.7 | ) | (65.8 | ) | 4.1 | |||||||
TNMP: | |||||||||||
Transmission | (23.2 | ) | (22.5 | ) | (0.7 | ) | |||||
Distribution | (26.8 | ) | (12.8 | ) | (14.0 | ) | |||||
AMS | — | (1.0 | ) | 1.0 | |||||||
(50.0 | ) | (36.3 | ) | (13.7 | ) | ||||||
Corporate and Other: | |||||||||||
Computer hardware and software | (6.0 | ) | (10.1 | ) | 4.1 | ||||||
PNMR Development utility plant additions | — | (2.6 | ) | 2.6 | |||||||
(6.0 | ) | (12.7 | ) | 6.7 | |||||||
$ | (117.7 | ) | $ | (114.8 | ) | $ | (2.9 | ) | |||
Cash Inflows on the Westmoreland Loan | |||||||||||
Principal payments | $ | 5.6 | $ | 9.6 | $ | (4.0 | ) | ||||
Cash Inflows (Outflows) Related to NMRD | |||||||||||
Investments in NMRD | $ | (5.0 | ) | $ | — | $ | (5.0 | ) |
• | Short-term borrowings decreased $66.7 million in 2018 compared to an increase of $16.0 million in 2017, resulting in a net decrease in cash flows from financing activities of $82.7 million |
• | In 2018, PNMR issued $300.0 million aggregate principle amount of 3.250% Senior Unsecured Notes utilizing the proceeds to repay the $150.0 million PNMR 2015 Term Loan Agreement |
• | In accordance with the BTMU Term Loan Agreement, NM Capital made principal payments of $5.0 million in 2018 compared to $9.4 million in 2017 |
• | Ability to earn a fair return on equity |
• | Results of operations |
• | Ability to obtain required regulatory approvals |
• | Conditions in the financial markets |
• | Credit ratings |
• | 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 |
2018 | 2019-2022 | Total | |||||||||
(In millions) | |||||||||||
Construction expenditures | $ | 500.8 | $ | 2,210.8 | $ | 2,711.6 | |||||
Dividends on PNMR common stock | 84.4 | 337.7 | 422.1 | ||||||||
Dividends on PNM preferred stock | 0.5 | 2.1 | 2.6 | ||||||||
Total capital requirements | $ | 585.7 | $ | 2,550.6 | $ | 3,136.3 |
Three Months Ended March 31, 2018 | ||||||||
Range of Borrowings | Low | High | ||||||
(In millions) | ||||||||
PNM: | ||||||||
PNM Revolving Credit Facility | $ | — | $ | 64.2 | ||||
PNM 2017 New Mexico Credit Facility | — | 20.0 | ||||||
TNMP Revolving Credit Facility | — | 24.4 | ||||||
PNMR Revolving Credit Facility | 29.1 | 210.0 | ||||||
PNMR Development Revolving Credit Facility | — | 21.5 |
PNMR | PNM | TNMP | |||
S&P | |||||
Corporate rating | BBB+ | BBB+ | BBB+ | ||
Senior secured debt | * | * | A | ||
Senior unsecured debt | BBB | BBB+ | * | ||
Preferred stock | * | BBB- | * | ||
Moody’s | |||||
Issuer rating | Baa3 | Baa2 | A3 | ||
Senior secured debt | * | * | A1 | ||
Senior unsecured debt | Baa3 | Baa2 | * | ||
* Not applicable |
PNM | TNMP | PNMR Separate | PNMR Development | Consolidated | |||||||||||||||
(In millions) | |||||||||||||||||||
Financing capacity: | |||||||||||||||||||
Revolving credit facility | $ | 400.0 | $ | 75.0 | $ | 300.0 | $ | 24.5 | $ | 799.5 | |||||||||
PNM 2017 New Mexico Credit Facility | 40.0 | — | — | — | 40.0 | ||||||||||||||
Total financing capacity | $ | 440.0 | $ | 75.0 | $ | 300.0 | $ | 24.5 | $ | 839.5 | |||||||||
Amounts outstanding as of April 23, 2018: | |||||||||||||||||||
Revolving credit facility | $ | — | $ | 40.4 | $ | 96.2 | $ | 24.5 | $ | 161.1 | |||||||||
PNM New Mexico Credit Facility | — | — | — | — | — | ||||||||||||||
Letters of credit | 2.5 | 0.1 | 6.4 | — | 9.0 | ||||||||||||||
Total short-term debt and letters of credit | 2.5 | 40.5 | 102.6 | 24.5 | 170.1 | ||||||||||||||
Remaining availability as of April 23, 2018 | $ | 437.5 | $ | 34.5 | $ | 197.4 | $ | — | $ | 669.4 | |||||||||
Invested cash as of April 23, 2018 | $ | 8.6 | $ | — | $ | 0.9 | $ | — | $ | 9.5 |
March 31, 2018 | December 31, 2017 | ||||
PNMR | |||||
PNMR common equity | 39.4 | % | 40.9 | % | |
Preferred stock of subsidiary | 0.3 | % | 0.3 | % | |
Long-term debt | 60.3 | % | 58.8 | % | |
Total capitalization | 100.0 | % | 100.0 | % | |
PNM | |||||
PNM common equity | 46.1 | % | 46.0 | % | |
Preferred stock | 0.4 | % | 0.4 | % | |
Long-term debt | 53.5 | % | 53.6 | % | |
Total capitalization | 100.0 | % | 100.0 | % | |
TNMP | |||||
Common equity | 57.2 | % | 56.9 | % | |
Long-term debt | 42.8 | % | 43.1 | % | |
Total capitalization | 100.0 | % | 100.0 | % |
• | The ability of PNM and TNMP to recover costs and earn allowed returns in regulated jurisdictions, including the impacts of the NMPRC orders in PNM’s NM 2015 Rate Case and NM 2016 Rate Case, appeals of those orders, the deferral of the issue of PNM’s prudence of continuation of participation in Four Corners to PNM’s next rate case and recovery of PNM’s investments in that plant, and any actions resulting from PNM’s 2017 IRP and the impact on service levels for PNM customers if the ultimate outcomes do not provide 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 and NM 2016 Rate Case, including appeals, and TNMP’s rate case anticipated to be filed in May 2018 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 |
• | 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 order in the NM 2015 Rate Case and NM 2016 Rate Case, appeals of those orders, and PNM’s 2017 IRP |
• | 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 of the NMPRC for ratemaking purposes |
• | 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 and NM 2016 Rate Case, including appeals |
• | 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 |
• | State and federal regulatory, legislative, executive, and judicial decisions and actions on ratemaking, tax, including the impacts 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 |
• | 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 |
• | 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 |
• | 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 |
• | PNMR: www.pnmresources.com |
• | PNM: www.pnm.com |
• | TNMP: www.tnmp.com |
• | 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 |
• | 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 |
Three Months Ended | |||||||
March 31, | |||||||
2018 | 2017 | ||||||
Economic Hedges | (In thousands) | ||||||
Sources of fair value gain (loss): | |||||||
Net fair value at beginning of period | $ | (94 | ) | $ | 2,885 | ||
Amount realized on contracts delivered during period | 26 | (2,007 | ) | ||||
Changes in fair value | 2 | 3,352 | |||||
Net mark-to-market change recorded in earnings | 28 | 1,345 | |||||
Net change recorded as regulatory assets and liabilities | (175 | ) | (4 | ) | |||
Net fair value at end of period | $ | (241 | ) | $ | 4,226 |
Rating (1) | Credit Risk Exposure(2) | Number of Counter-parties >10% | Net Exposure of Counter-parties >10% | ||||||
(Dollars in thousands) | |||||||||
External ratings: | |||||||||
Investment grade | $ | 3,141 | 1 | $ | 1,281 | ||||
Non-investment grade | 273 | — | — | ||||||
Split ratings | 130 | — | — | ||||||
Internal ratings: | |||||||||
Investment grade | 46 | — | — | ||||||
Non-investment grade | 769 | 1 | 648 | ||||||
Total | $ | 4,359 | $ | 1,929 |
(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 and the Tri-State hazard sharing agreement), forward sales, and short-term sales. The gross |
• | The Clean Air Act – Regional Haze – SJGS |
• | The Clean Air Act – Regional Haze – Four Corners – Four Corners Federal Agency 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 |
• | PNM – New Mexico General Rate Cases |
• | PNM – Renewable Portfolio Standard |
• | PNM – Energy Efficiency and Load Management |
• | PNM – FPPAC Continuation Application |
• | PNM – Integrated Resource Plans |
• | PNM – San Juan Generating Station Unit 1 Outage |
• | TNMP – Order Related to Changes in Federal Income Tax Rates |
3.1 | PNMR | |
3.2 | PNM | |
3.3 | TNMP | |
3.4 | PNMR | |
3.5 | PNM | |
3.6 | TNMP | |
10.1 | PNMR | |
10.2 | PNMR | |
10.3 | PNMR | |
12.1 | PNMR | |
12.2 | PNM | |
12.3 | TNMP | |
31.1 | PNMR | |
31.2 | PNMR | |
31.3 | PNM | |
31.4 | PNM | |
31.5 | TNMP | |
31.6 | TNMP | |
32.1 | PNMR | |
32.2 | PNM | |
32.3 | TNMP | |
101.INS | PNMR, PNM, and TNMP | XBRL Instance Document |
101.SCH | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Schema Document |
101.CAL | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Presentation Linkbase Document |
PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO TEXAS-NEW MEXICO POWER COMPANY | ||
(Registrants) | ||
Date: | April 30, 2018 | /s/ Joseph D. Tarry |
Joseph D. Tarry | ||
Vice President, Finance and Controller | ||
(Officer duly authorized to sign this report) |
a) | Select the scorecard results from the appropriate Corporate Goals and Business Area Goals Scorecards; |
b) | Then multiply each result by the appropriate weighting for the scorecard as set forth in Table 2 of Attachment A; |
c) | Then multiply the total Vice President salaries for that Business Area by the Target Award Level as set forth in Table 3 of Attachment A; |
d) | Then multiply the result of each scorecard (Step b), expressed as a percentage of Target, by the aggregate base salaries of the Vice Presidents included in that Business Area (Step c); and |
e) | Sum the results for the Vice President participants. |
– | Officers who are newly hired during the Performance Period and are employed by the Company or an Affiliate on the day on which Awards are distributed for the Performance Period. |
– | Employees or Officers who are promoted, transferred or demoted during the Performance Period and are employed by the Company or an Affiliate on the day on which Awards are distributed for the Performance Period. |
– | Officers who are on leave of absence for any full month(s) during the Performance Period and are employed by the Company or an Affiliate on the day on which Awards are distributed for the Performance Period. |
– | Officers who terminate employment with the Company or an Affiliate during the Performance Period due to Impaction (as defined in the PNM Resources, Inc. Non-Union Severance Pay Plan), Retirement or Disability. |
– | Officers who die during the Performance Period, in which case the Award will be paid to the spouse of a married Officer, including a same sex spouse, or the estate of an unmarried Officer. |
– | Officers who terminate employment with the Company or an Affiliate on or before the date on which Awards are distributed for the Performance Period for any reason other than death, Impaction (as defined in the PNM Resources, Inc. Non-Union Severance Pay Plan), Retirement or Disability. As noted above, Officers who terminate employment with the Company or an Affiliate during the Performance Period due to a Qualifying Change in Control Termination may be entitled to receive a special payment pursuant to the PNM Resources, Inc. Officer Retention Plan in lieu of any payments under this Plan. |
– | Officers who elect voluntary separation or Retirement in lieu of termination for performance or misconduct. |
◦ |
Incentive EPS1 | |
No Award | Less than $1.82 |
Threshold | Greater than or equal to $1.82 and less than $1.87 |
Target | Greater than or equal to $1.87 and less than $1.97 |
Maximum | Greater than or equal to $1.97 |
Scorecard Results | ||
Scorecard Level | Corporate Weighting | Business Area Weighting |
CEO & Senior Officers | 100% | 0% |
Vice Presidents | 60% | 40% |
Award Levels | Threshold | Target | Maximum |
CEO | 55% | 110% | 220% |
EVP | 37.5% | 75% | 150% |
SVP | 27.5% | 55% | 110% |
Vice-Presidents | 20% | 40% | 80% |
• | The 2018 Long-Term Incentive Plan (the “Plan” or the “2018 Plan”) provides eligible Officers of PNM Resources, Inc. (the “Company” or “PNMR”) with the opportunity to earn Performance Share Awards (70% of the total opportunity) and time-vested Restricted Stock Rights Awards (30% of the total opportunity). For purposes of the Plan, “Officer” means any Officer of the Company who has the title of Chief Executive Officer, Executive Vice President, Senior Vice President or Vice President and who is in salary grade H18 or higher. |
• | The number of Performance Shares earned by an Officer for the Performance Period (as described below) will depend on the Officer’s position (e.g., Chief Executive Officer, Executive Vice President, Senior Vice President or Vice President) and base salary and the Company’s level of attainment of (1) an Earnings Growth Goal, (2) a Relative TSR Goal and (3) an FFO/Debt Ratio Goal, as described below and in Attachment A. |
• | The number of time-vested Restricted Stock Rights granted to an Officer at the end of each Performance Period will depend on the Officer’s position, the Officer’s base salary and the discretion of the Committee. |
• | The Performance Period began on January 1, 2018 and will end on December 31, 2020. |
• | The number of Performance Shares that an Officer will receive for the Performance Period will depend on the Company’s level of attainment of an Earnings Growth Goal, Relative TSR Goal and a FFO/Debt Ratio Goal. |
• | These goals and the corresponding Awards are described in the Performance Goal Table (Attachment A). |
• | The Company’s level of attainment (Threshold, Target or Maximum) of the Earnings Growth Goal, Relative TSR Goal and the FFO/Debt Ratio Goal determines the level of the Officer’s Performance Share Awards. |
• | An Officer’s Performance Share Award opportunities also will vary depending on the Officer’s position and the Officer’s base salary, all as determined in accordance with the Performance Share Award Opportunity Table (Attachment B). |
• | For purposes of determining the number of Performance Shares to which an Officer is entitled at any particular Award level, the value of one Performance Share shall be equal to the Fair Market Value of one share of the Company’s Stock on the relevant Grant Date and the Officer’s base salary shall equal the Officer’s base salary as of the first day of the Performance Period. |
• | After the Performance Period (generally between the next following January 1 and March 15), the Committee will consider whether to grant time-vested Restricted Stock Rights Awards to the participating Officers. |
• | If the Committee, with the approval of the Board, decides to make a time-vested Restricted Stock Rights Award to a particular Officer, it must adopt a written resolution to that effect. In the resolution, the Committee will establish the Grant Date for the time-vested Restricted Stock Rights Award. |
• | An Officer’s time-vested Restricted Stock Rights Award opportunity will vary depending on the Officer’s position and the Officer’s base salary, all as determined in accordance with the attached Time-Vested Restricted Stock Rights Award Opportunity Table (Attachment C). The Committee reserves the discretion to grant an Award that is less than the opportunity set forth in the Table or to grant no time-vested Restricted Stock Rights Award to a particular Officer. |
• | For purposes of determining the number of time-vested Restricted Stock Rights to which an Officer will be entitled, the value of one time-vested Restricted Stock Right shall be equal to the Fair Market Value of one share of the Company’s Stock on the Grant Date specified in the Committee’s resolution and the Officer’s base salary shall equal the Officer’s base salary on the Grant Date. |
• | All of the Awards will be made pursuant to the PNM Resources, Inc. 2014 Performance Equity Plan, as amended (the “PEP”) or any successor to the PEP. Any references in the Plan to the PEP shall be deemed to be a reference to the corresponding provisions of any successor to the PEP. |
• | All of the Awards will be subject to the standard Terms and Conditions attached hereto as Attachment D. |
• | The Grant Date for the Performance Share Awards is March 2, 2018 (the first trading day after expiration of the current black-out period, as determined in accordance with the Company’s Equity Compensation Awards Policy). |
• | A prorated Performance Share Award will be provided to an Officer who has a Separation from Service in the second half of the Performance Period (in other words, between July 1, 2019 and December 31, 2020) due to death, Disability, Retirement or Impaction. A prorated Award will not be paid to an Officer who incurs a Separation from Service for any of these reasons during the first half of the Performance Period or to an Officer who incurs a Separation from Service for any other reason other than a Qualifying Change in Control Termination prior to the last day of the Performance Period. |
• | The prorated Award will be calculated at the end of the Performance Period based on actual performance during the Performance Period. The proration will be made based on the number of full months of service completed by the Officer during the Performance Period, using the proration rules described in Section 11.1(a)(iv)(2) of |
• | Notwithstanding any provision in the Plan to the contrary, Company’s Executive Vice President and Chief Financial Officer (determined as of the first day of the Performance Period) shall be entitled to a full (rather than a prorated) Performance Share Award, calculated at the end of the Performance Period based on actual performance during the Performance Period, if he has a Separation from Service at any time during the Performance Period for reasons other than for Cause. |
• | Upon an Officer’s Separation from Service due to a Qualifying Change in Control Termination, a prorated portion of the Performance Shares will vest at the end of the Performance Period based on the level of achievement of the performance goals in accordance with the applicable provisions of the PEP. |
• | If an individual ceases to be an Officer during a Performance Period but remains employed by the Company or its Affiliates, the Committee may grant a prorated Performance Share Award to the former Officer on such terms and conditions as the Committee deems to be appropriate as long as the individual was an Officer for at least half of the Performance Period. |
• | If an individual becomes an Officer during a Performance Period, the Committee may grant a prorated Performance Share Award to the new Officer on such terms and conditions as the Committee deems to be appropriate. |
• | For the avoidance of doubt, the Performance Share Awards are not intended to qualify as Performance-Based Awards granted pursuant to Section 10 of the PEP. As a result, such Awards are not subject to the requirements of Section 10 of the PEP. |
• | All Awards issued under this Plan are subject to potential forfeiture or recovery to the fullest extent called for by any Clawback Policy that may be adopted by the Company. By accepting an Award, an Officer consents to the Clawback Policy and agrees to be bound by and comply with the Clawback Policy and to return the full amount required by the Clawback Policy. |
Goal | Threshold Level1 | Target Level1 | Maximum Level1,2 |
Earnings Growth3 If the Company’s Earnings Growth on the last day of the Performance Period places it in the Threshold, Target or Maximum Level range for the Performance Period, the Officer will be entitled to receive 50% of the Threshold, Target or Maximum Award as determined in accordance with the Performance Share Award Opportunity Table. | At least 2%, but less than 3% | At least 3%, but less than 5% | At least 5% |
Relative TSR4 If the Company’s Relative TSR for the Performance Period places it in the Threshold, Target or Maximum Level range shown to the right, the Officer will be entitled to receive 25% of the Threshold, Target or Maximum Award as determined in accordance with the Performance Share Award Opportunity Table. | Greater than or equal to the 35th percentile and less than the 50th percentile | Greater than or equal to the 50th percentile and less than the 95th percentile | Greater than or equal to the 95th percentile |
FFO/Debt Ratio5 If the Company’s FFO/Debt Ratio on the last day of the Performance Period places it in the Threshold, Target or Maximum Level range for the Performance Period, the Officer will be entitled to receive 25% of the Threshold, Target or Maximum Award as determined in accordance with the Performance Share Award Opportunity Table. | At least 14%, but less than 16% | At least 16%, but less than 18% | At least 18% |
Officer Level | Threshold Award | Target Award | Maximum Award |
CEO | Performance Shares = 87.5% of base salary | Performance Shares = 175% of base salary | Performance Shares = 350% of base salary |
EVP | Performance Shares = 43.75% of base salary | Performance Shares = 87.5% of base salary | Performance Shares = 175% of base salary |
SVP | Performance Shares = 29.75% of base salary | Performance Shares = 59.5% of base salary | Performance Shares = 119% of base salary |
VP | Performance Shares = 17.5% of base salary | Performance Shares = 35% of base salary | Performance Shares = 70% of base salary |
Officer Level | Award |
CEO | Restricted Stock Rights = 75% of base salary |
EVP | Restricted Stock Rights = 37.5% of base salary |
SVP | Restricted Stock Rights = 25.5% of base salary |
VP | Restricted Stock Rights = 15% of base salary |
Plan: | The PNM Resources, Inc. Executive Choice Account Plan, as set forth in this document. |
Plan Name: | PNM Resources, Inc. Executive Choice Account Plan. |
Exhibit 12.1 | |||||||||||||||||||||||||
PNM RESOURCES, INC. AND SUBSIDIARIES | |||||||||||||||||||||||||
Ratio of Earnings to Fixed Charges | |||||||||||||||||||||||||
(In thousands, except ratio) | |||||||||||||||||||||||||
Three Months Ended | Year Ended December 31, | ||||||||||||||||||||||||
March 31, 2018 | 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||||||
Fixed charges, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Interest expensed and capitalized | $ | 33,798 | $ | 130,024 | $ | 129,592 | $ | 117,932 | $ | 117,337 | $ | 118,880 | |||||||||||||
Amortization of debt premium, discount, and expenses | 1,120 | 4,106 | 3,779 | 3,575 | 4,194 | 3,716 | |||||||||||||||||||
Estimated interest factor of lease rental charges | 644 | 2,567 | 2,747 | 3,298 | 4,686 | 5,847 | |||||||||||||||||||
Preferred dividend requirements of subsidiary | 138 | 1,249 | 781 | 784 | 809 | 800 | |||||||||||||||||||
Total Fixed Charges | $ | 35,700 | $ | 137,946 | $ | 136,899 | $ | 125,589 | $ | 127,026 | $ | 129,243 | |||||||||||||
Earnings, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Earnings before income taxes and non-controlling interest | $ | 19,582 | $ | 225,759 | $ | 195,174 | $ | 46,153 | $ | 200,647 | $ | 175,069 | |||||||||||||
Fixed charges as above | 35,700 | 137,946 | 136,899 | 125,589 | 127,026 | 129,243 | |||||||||||||||||||
Interest capitalized | (2,392 | ) | (8,806 | ) | (7,964 | ) | (9,753 | ) | (6,256 | ) | (5,209 | ) | |||||||||||||
Non-controlling interest in earnings of Valencia | (3,677 | ) | (15,017 | ) | (14,519 | ) | (14,910 | ) | (14,127 | ) | (14,521 | ) | |||||||||||||
Preferred dividend requirements of subsidiary | (138 | ) | (1,249 | ) | (781 | ) | (784 | ) | (809 | ) | (800 | ) | |||||||||||||
Earnings Available for Fixed Charges | $ | 49,075 | $ | 338,633 | $ | 308,809 | $ | 146,295 | $ | 306,481 | $ | 283,782 | |||||||||||||
Ratio of Earnings to Fixed Charges | 1.37 | 2.45 | 1 | 2.26 | 2 | 1.16 | 3 | 2.41 | 4 | 2.20 | 5 | ||||||||||||||
1 Earnings before income taxes and non-controlling interest for the year ended December 31, 2017 includes a pre-tax loss of $27.0 million due to the write-off of regulatory disallowances and restructuring costs at PNM. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.65 for 2017. | |||||||||||||||||||||||||
2 Earnings before income taxes and non-controlling interest for the year ended December 31, 2016 includes a pre-tax loss of $15.0 million due to the write-off of regulatory disallowances and restructuring costs at PNM. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.37 for 2016. | |||||||||||||||||||||||||
3 Earnings before income taxes and non-controlling interest for the year ended December 31, 2015 includes a pre-tax loss of $167.5 million due to the write-off of regulatory disallowances and restructuring costs at PNM. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.50 for 2015. | |||||||||||||||||||||||||
4 Earnings before income taxes and non-controlling interest for the year ended December 31, 2014 includes a pre-tax loss of $1.1 million due to the write-off of regulatory disallowances at PNM. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.42 for 2014. | |||||||||||||||||||||||||
5 Earnings before income taxes and non-controlling interest for the year ended December 31, 2013 includes a pre-tax loss of $12.2 million due to the write-off of regulatory disallowances at PNM. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.29 for 2013. | |||||||||||||||||||||||||
Exhibit 12.2 | |||||||||||||||||||||||||
PUBLIC SERVICE COMPANY OF NEW MEXICO | |||||||||||||||||||||||||
Ratio of Earnings to Fixed Charges | |||||||||||||||||||||||||
(In thousands, except ratio) | |||||||||||||||||||||||||
Three Months Ended | Year Ended December 31, | ||||||||||||||||||||||||
March 31, 2018 | 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||||||
Fixed charges, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Interest expensed and capitalized | $ | 21,929 | $ | 86,121 | $ | 89,502 | $ | 84,695 | $ | 79,834 | $ | 79,769 | |||||||||||||
Amortization of debt premium, discount and expenses | 634 | 2,677 | 2,312 | 1,978 | 1,944 | 1,879 | |||||||||||||||||||
Estimated interest factor of lease rental charges | 287 | 1,182 | 1,217 | 1,532 | 2,541 | 3,732 | |||||||||||||||||||
Total Fixed Charges | $ | 22,850 | $ | 89,980 | $ | 93,031 | $ | 88,205 | $ | 84,319 | $ | 85,380 | |||||||||||||
Earnings, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Earnings (loss) before income taxes and non-controlling interest | $ | 11,166 | $ | 168,968 | $ | 132,860 | $ | (13,082 | ) | $ | 154,086 | $ | 151,480 | ||||||||||||
Fixed charges as above | 22,850 | 89,980 | 93,031 | 88,205 | 84,319 | 85,380 | |||||||||||||||||||
Non-controlling interest in earnings of Valencia | (3,677 | ) | (15,017 | ) | (14,519 | ) | (14,910 | ) | (14,127 | ) | (14,521 | ) | |||||||||||||
Interest capitalized | (1,937 | ) | (6,917 | ) | (6,094 | ) | (8,530 | ) | (5,211 | ) | (4,420 | ) | |||||||||||||
Earnings Available for Fixed Charges | $ | 28,402 | $ | 237,014 | $ | 205,278 | $ | 51,683 | $ | 219,067 | $ | 217,919 | |||||||||||||
Ratio of Earnings to Fixed Charges | 1.24 | 2.63 | 1 | 2.21 | 2 | 0.59 | 3 | 2.60 | 4 | 2.55 | 5 | ||||||||||||||
1 Earnings (loss) before income taxes and non-controlling interest for the year ended December 31, 2017 includes a pre-tax loss of $27.0 million due to the write-off of regulatory disallowances and restructuring costs. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.93 for 2017. | |||||||||||||||||||||||||
2 Earnings (loss) before income taxes and non-controlling interest for the year ended December 31, 2016 includes a pre-tax loss of $15.0 million due to the write-off of regulatory disallowances and restructuring costs. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.37 for 2016. | |||||||||||||||||||||||||
3 The shortfall in earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $36.5 million for the year ended December 31, 2015. Earnings (loss) before income taxes includes a pre-tax loss of $167.5 million due to the write-off of regulatory disallowances and restructuring costs. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.48 for 2015. | |||||||||||||||||||||||||
4 Earnings (loss) before income taxes and non-controlling interest for the year ended December 31, 2014 includes a pre-tax loss of $1.1 million due to the write-off of regulatory disallowances. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.61 for 2014. | |||||||||||||||||||||||||
5 Earnings (loss) before income taxes and non-controlling interest for the year ended December 31, 2013 includes a pre-tax loss of $12.2 million due to the write-off of regulatory disallowances. If that loss was excluded, the Ratio of Earnings to Fixed Charges would have been 2.70 for 2013. | |||||||||||||||||||||||||
Exhibit 12.3 | |||||||||||||||||||||||||
TEXAS-NEW MEXICO POWER COMPANY | |||||||||||||||||||||||||
Ratio of Earnings to Fixed Charges | |||||||||||||||||||||||||
(In thousands, except ratio) | |||||||||||||||||||||||||
Three Months Ended | Year Ended December 31, | ||||||||||||||||||||||||
March 31, 2018 | 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||||||
Fixed charges, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Interest expensed and capitalized | $ | 7,448 | $ | 28,739 | $ | 27,698 | $ | 25,875 | $ | 24,941 | $ | 24,481 | |||||||||||||
Amortization of debt premium, discount and expenses | 318 | 1,048 | 1,039 | 1,100 | 1,195 | 1,159 | |||||||||||||||||||
Estimated interest factor of lease rental charges | 313 | 1,190 | 1,249 | 1,229 | 1,311 | 1,241 | |||||||||||||||||||
Total Fixed Charges | $ | 8,079 | $ | 30,977 | $ | 29,986 | $ | 28,204 | $ | 27,447 | $ | 26,881 | |||||||||||||
Earnings, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Earnings from continuing operations before income taxes | $ | 11,888 | $ | 67,071 | $ | 65,508 | $ | 66,088 | $ | 60,330 | $ | 46,711 | |||||||||||||
Fixed charges as above | 8,079 | 30,977 | 29,986 | 28,204 | 27,447 | 26,881 | |||||||||||||||||||
Interest capitalized | (361 | ) | (1,189 | ) | (877 | ) | (593 | ) | (609 | ) | (361 | ) | |||||||||||||
Earnings Available for Fixed Charges | $ | 19,606 | $ | 96,859 | $ | 94,617 | $ | 93,699 | $ | 87,168 | $ | 73,231 | |||||||||||||
Ratio of Earnings to Fixed Charges | 2.43 | 3.13 | 3.16 | 3.32 | 3.18 | 2.72 | |||||||||||||||||||
1. | I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | April 30, 2018 | By: | /s/ Patricia K. Collawn |
Patricia K. Collawn | |||
Chairman, President and Chief Executive Officer | |||
PNM Resources, Inc. |
1. | I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | April 30, 2018 | By: | /s/ Charles N. Eldred |
Charles N. Eldred | |||
Executive Vice President and | |||
Chief Financial Officer | |||
PNM Resources, Inc. |
1. | I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | April 30, 2018 | By: | /s/ Patricia K. Collawn |
Patricia K. Collawn | |||
President and Chief Executive Officer | |||
Public Service Company of New Mexico |
1. | I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | April 30, 2018 | By: | /s/ Charles N. Eldred |
Charles N. Eldred | |||
Executive Vice President and | |||
Chief Financial Officer | |||
Public Service Company of New Mexico |
1. | I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | April 30, 2018 | By: | /s/ Patricia K. Collawn |
Patricia K. Collawn | |||
Chief Executive Officer | |||
Texas-New Mexico Power Company |
1. | I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | April 30, 2018 | By: | /s/ Charles N. Eldred |
Charles N. Eldred | |||
Executive Vice President and | |||
Chief Financial Officer | |||
Texas-New Mexico Power Company |
(1) | the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: | April 30, 2018 | By: | /s/ Patricia K. Collawn |
Patricia K. Collawn | |||
Chairman, President and Chief Executive Officer | |||
PNM Resources, Inc. | |||
By: | /s/ Charles N. Eldred | ||
Charles N. Eldred | |||
Executive Vice President and | |||
Chief Financial Officer |
(1) | the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: | April 30, 2018 | By: | /s/ Patricia K. Collawn |
Patricia K. Collawn | |||
President and Chief Executive Officer | |||
Public Service Company of New Mexico | |||
By: | /s/ Charles N. Eldred | ||
Charles N. Eldred | |||
Executive Vice President and | |||
Chief Financial Officer |
(1) | the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: | April 30, 2018 | By: | /s/ Patricia K. Collawn |
Patricia K. Collawn | |||
Chief Executive Officer | |||
Texas-New Mexico Power Company | |||
By: | /s/ Charles N. Eldred | ||
Charles N. Eldred | |||
Executive Vice President and | |||
Chief Financial Officer |
Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit | $ (283) | $ (3,030) |
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit) | 668 | 1,078 |
Pension liability adjustment, income tax expense (benefit) | (480) | (480) |
Change in fair market value, income tax (expense) benefit | (472) | (631) |
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit) | 13 | (44) |
PNM | ||
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit | (283) | (3,030) |
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit) | 668 | 1,078 |
Pension liability adjustment, income tax expense (benefit) | $ (480) | $ (631) |
Condensed Consolidated Statements of Cash Flows Condensed Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
Mar. 31, 2017 |
---|---|---|---|
Restricted Cash Included in Other Current Assets on Condensed Consolidated Balance Sheets: | |||
At beginning of period | $ 0 | $ 1,000 | $ 1,000 |
At end of period | 0 | 0 | 1,000 |
PNM | |||
Restricted Cash Included in Other Current Assets on Condensed Consolidated Balance Sheets: | |||
At beginning of period | 0 | 1,000 | 1,000 |
At end of period | $ 0 | $ 0 | $ 1,000 |
Condensed Consolidated Statement of Changes in Equity - USD ($) $ in Thousands |
Total |
Total PNMR Common Stockholders’ Equity |
Common Stock |
AOCI |
Retained Earnings |
Non- controlling Interest in Valencia |
PNM |
PNM
Total PNMR Common Stockholders’ Equity
|
PNM
Common Stock
|
PNM
AOCI
|
PNM
Retained Earnings
|
PNM
Non- controlling Interest in Valencia
|
Texas-New Mexico Power Company |
Texas-New Mexico Power Company
Common Stock
|
Texas-New Mexico Power Company
Paid-in Capital
|
Texas-New Mexico Power Company
Retained Earnings
|
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Net earnings before subsidiary preferred stock dividends | $ 26,446 | $ 20,110 | ||||||||||||||
Net earnings | 22,862 | 16,658 | $ 7,604 | |||||||||||||
Total other comprehensive income | 3,993 | 4,038 | ||||||||||||||
Subsidiary preferred stock dividends | (132) | |||||||||||||||
Dividends declared on common stock | (9,900) | |||||||||||||||
Ending balance at Mar. 31, 2017 | (88,458) | |||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Cumulative effect adjustment (Note 7) | (11,208) | $ (11,208) | $ 11,208 | (11,208) | $ (11,208) | $ 11,208 | ||||||||||
Balance, as adjusted | 1,761,448 | $ 1,695,253 | $ 1,157,665 | (107,148) | 644,736 | $ 66,195 | 1,488,369 | $ 1,422,174 | $ 1,264,918 | (108,301) | 265,557 | $ 66,195 | ||||
Beginning balance at Dec. 31, 2017 | 1,761,448 | 1,695,253 | 1,157,665 | (95,940) | 633,528 | 66,195 | 1,488,369 | 1,422,174 | 1,264,918 | (97,093) | 254,349 | 66,195 | ||||
Beginning balance TNMP at Dec. 31, 2017 | 1,695,253 | 1,422,174 | 634,405 | $ 64 | $ 504,166 | $ 130,175 | ||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Net earnings before subsidiary preferred stock dividends | 18,799 | 15,122 | 15,122 | 3,677 | 11,514 | 7,837 | 7,837 | 3,677 | ||||||||
Net earnings | 14,990 | 7,837 | 9,413 | 9,413 | ||||||||||||
Total other comprehensive income | 1,628 | 1,628 | 1,628 | 282 | 282 | 282 | ||||||||||
Subsidiary preferred stock dividends | (132) | (132) | (132) | |||||||||||||
Dividends declared on preferred stock | (132) | (132) | (132) | |||||||||||||
Dividends declared on common stock | (21,108) | (21,108) | (21,108) | (1,024) | (1,024) | |||||||||||
Proceeds from stock option exercise | 802 | 802 | 802 | |||||||||||||
Awards of common stock | (10,845) | (10,845) | (10,845) | |||||||||||||
Stock based compensation expense | 2,894 | 2,894 | 2,894 | |||||||||||||
Valencia’s transactions with its owner | (4,472) | (4,472) | (4,472) | (4,472) | ||||||||||||
Ending balance at Mar. 31, 2018 | 1,749,014 | $ 1,683,614 | $ 1,150,516 | $ (105,520) | $ 638,618 | $ 65,400 | 1,495,561 | $ 1,430,161 | $ 1,264,918 | $ (108,019) | $ 273,262 | $ 65,400 | ||||
Ending balance TNMP at Mar. 31, 2018 | $ 1,683,614 | $ 1,430,161 | $ 642,794 | $ 64 | $ 504,166 | $ 138,564 |
Significant Accounting Policies and Responsibility for Financial Statements |
3 Months Ended |
---|---|
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies and Responsibility for Financial Statements | Significant Accounting Policies and Responsibility for Financial Statements Financial Statement Preparation In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at March 31, 2018 and December 31, 2017 and the consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2018 and 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 2017 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2018 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 2017 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 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. 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 (Note 15). All intercompany transactions and balances have been eliminated. 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. TNMP declared and paid cash dividends on common stock to PNMR of $1.0 million and $9.9 million in the three months ended March 31, 2018 and 2017. Investment in NM Renewable Development, LLC As discussed in Note 1 of the 2017 Annual Reports on Form 10-K, in September 2017, PNMR Development and AEP OnSite Partners created NMRD to pursue the acquisition, development, and ownership of renewable energy projects, primarily in the state of New Mexico. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. NMRD’s current renewable energy capacity in operation is 21.8 MW. NMRD also has 10 MW of solar PV facilities under construction that will be completed in mid-2018. PNMR accounts for its investment in NMRD using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over NMRD and its operations. In February 2018, PNMR Development made cash contributions of $5.0 million to NMRD for its construction activities. For the three months ended March 31, 2018, NMRD had revenues of $0.4 million and net earnings of $0.1 million. At March 31, 2018, NMRD had $3.9 million in cash, $0.4 million in accounts receivable, $43.3 million of property, plant, and equipment and other assets, $4.5 million in accounts payable and accrued expenses, and $43.1 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 that amounts generally described as restricted cash and restricted cash equivalents (“restricted cash”) 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 statement of financial position and 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 the statement of cash flows in each period presented. 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 is restricted and must be used for payments required under that agreement or for taxes and fees. Cash held by NM Capital is included in Cash and cash equivalents on the balance sheets of PNMR and amounted to $1.4 million at December 31, 2016 and $1.5 million at March 31, 2018, but was less than $0.1 million at March 31, 2017 and December 31, 2017. The Company adopted ASU 2016-18 as of January 1, 2018, its required effective date. In accordance with the standard, PNM made retrospective adjustments to its Condensed Consolidated Statements of Cash Flows for the three months ending March 31, 2017 to increase beginning cash, restricted cash, and equivalents at January 1, 2017 by $1.0 million and ending cash, restricted cash, and equivalents at March 31, 2017 by $1.0 million. No other changes were made to the Condensed Consolidated Financial Statements in connection with the adoption of ASU 2016-18. 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 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, 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. At adoption, ASU 2016-02 requires that leases be recognized and measured as of the earliest period presented using a modified retrospective approach with all periods presented being restated and presented under the new guidance. 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 2017 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. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. 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. The Company has formed a project team, conducted outreach activities across its lines of business, and made significant progress in identifying arrangements that may be classified as leases under ASU 2016-02 in addition to its existing operating lease arrangements. 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 arrangement 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 throughout 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. 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 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 effective as of January 1, 2020, its required effective date, although early adoption is permitted beginning on January 1, 2019. The Company 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 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 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 2017-12 – 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. As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 2017 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 2017 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. |
Segment Information |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Information | Segment Information The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided. PNM PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also 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 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, NM Capital, and the equity method investment in NMRD are also included in Corporate and Other. The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. PNMR SEGMENT INFORMATION
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Accumulated Other Comprehensive Income (Loss) |
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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2018 and 2017 is as follows:
Pre-tax amounts reclassified from AOCI related to Unrealized Gains on Available-for-Sale Securities are included in Gains on investment securities in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to Pension Liability Adjustment are reclassified to Other Income and Deductions – Other (deductions) in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to Fair Value Adjustment for Cash Flow Hedges are reclassified to Interest Charges in the Condensed Consolidated Statements of Earnings. An insignificant amount is included in capitalized interest. The income tax impacts of all amounts reclassified from AOCI are included in Income Taxes in the Condensed Consolidated Statements of Earnings. |
Earnings Per Share |
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Earnings Per Share | Earnings Per Share In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows:
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Electric Operating Revenues |
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Electric Operating Revenues | 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. 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. 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 also presented. 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 or leases transmission lines, 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. 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. 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 (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 for the three months ended March 31, 2018 by the type of customer is presented in the table below. The table also reflects ARP revenues and Other revenues.
For the three months ended March 31, 2017, ARP revenues and Other electric operating revenues were $1.1 million and $28.4 million for PNM and $3.5 million and none for TNMP. 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 $58.7 million at March 31, 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 March 31, 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:
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Variable Interest Entities |
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Variable Interest Entities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Variable Interest Entities | Variable Interest Entities GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity (“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 2017 Annual Reports on Form 10-K. Valencia PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operation and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three months ended March 31, 2018 and 2017, PNM paid $4.9 million and $4.9 million for fixed charges and $0.3 million and $0.1 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
Financial Position
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 are required quarterly thereafter. Interest is also paid quarterly beginning on May 3, 2016. At March 31, 2018, the amount outstanding under the Westmoreland Loan was $51.0 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 $0.9 million plus interest of $1.8 million is due on May 1, 2018. As of April 23, 2018, $2.7 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 foreclose on the equity of WSJ or the assets used in 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 foreclose on 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 SJGS CSA. Also, much of the mine reclamation activities will not be performed until after the expiration of the SJGS 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. On March 28, 2018, NM Capital executed an extension and waiver agreement with WSJ, which waived a technical event of default by WSJ under the Westmoreland Loan. This waiver relates solely to the required delivery of the financial statements of Westmoreland, WSJ’s parent company, and expires on the earlier of May 1, 2019 or the occurrence of any other event of default. On April 2, 2018, Westmoreland filed its Annual Report on Form 10-K for the year ended December 31, 2017 with the SEC. In the Westmoreland Form 10-K, Westmoreland indicated that it has 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.” As mentioned above, in January 2016, NM Capital made the Westmoreland Loan to WSJ, which is a ring-fenced, bankruptcy remote subsidiary of Westmoreland. The Westmoreland Loan is secured by the equity interests and assets of WSJ. A bankruptcy of Westmoreland would not constitute a default by WSJ under the Westmoreland Loan and WSJ continues to perform as required by the Westmoreland Loan other than the technical default covered by the March 28, 2018 waiver. 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. 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 Westmoreland Loan and the letter of credit support constitute PNMR’s maximum exposure to loss from the VIEs. |
Fair Value of Derivative and Other Financial Instruments |
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Fair Value of Derivative and Other Financial Instruments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments | Fair Value of Derivative and Other Financial Instruments 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 2017 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 customers. PNM is exposed to market risk for the needs of its customers not covered under a FPPAC. PNM was exposed to market risk for its share of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 became a jurisdictional resource to serve New Mexico retail customers. Beginning January 1, 2018, PNM is exposed to market risk for its 65 MW interest in SJGS Unit 4, which is held as merchant plant as ordered by the NMPRC (Note 11). PNM entered into agreements to sell 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. 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 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. 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 three months ended March 31, 2018 and the year ended December 31, 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 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:
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 $4.4 million at March 31, 2018 and $4.6 million at December 31, 2017, which result from PNM’s hazard sharing arrangements with Tri-State. The hazard sharing arrangements are net-settled upon delivery. Other amounts that could be offset under master netting agreements were immaterial. At March 31, 2018 and December 31, 2017, PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at March 31, 2018 and December 31, 2017, amounts posted as cash collateral under margin arrangements were $0.5 million and $0.8 million. At March 31, 2018 and December 31, 2017, obligations to return cash collateral were $0.9 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 $0.2 million of current liabilities at March 31, 2018 related to this plan. The offset to this amount is recorded as a regulatory asset on the Condensed Consolidated Balance Sheets. There were no amounts hedged under this plan as of December 31, 2017. 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.
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:
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 March 31, 2018 and December 31, 2017, PNM had $0.1 million and zero of such contracts in a liability position. 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. Investment securities are carried at fair value. Investment 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 March 31, 2018 and December 31, 2017, the fair value of investment securities included $294.0 million and $293.7 million for the NDT and $30.0 million and $29.8 million for the mine reclamation trusts. 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 disclosure 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 $11.2 million to reclassify unrealized holding gains on equity securities held in the NDT and coal mine reclamation trusts from AOCI to retained earnings on the 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.
The proceeds and gross realized gains and losses on the disposition of 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 ($1.2) million and $1.1 million for the three months ended March 31, 2018 and 2017.
Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. At March 31, 2018 and December 31, 2017, PNMR’s held-to-maturity securities consist of the Westmoreland Loan. The Company has no available-for-sale debt securities or held-to-maturity debt 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 March 31, 2018, the available-for-sale and held-to-maturity debt securities had the following final maturities:
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. The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the three months ended March 31, 2018 or the year ended December 31, 2017. For investment securities, Level 2 and Level 3 fair values are provided by fund managers utilizing a pricing service. For 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. The valuation of Level 3 investments 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 using an internal valuation model of discounted cash flows that takes 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 it investments in equity instruments as available-for-sale securities beginning January 1, 2018.
A reconciliation of the changes in Level 3 fair value measurements is as follows:
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:
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Stock-Based Compensation |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock-Based Compensation | Stock-Based Compensation PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 13 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, 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. Awards of restricted stock to non-employee members of the Board are expensed over a one 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 over the performance period as required service is provided and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At March 31, 2018 and December 31, 2017, PNMR had unrecognized expense related to stock awards of $5.8 million and $3.8 million, which are expected to be recognized over an average of 2.04 and 1.53 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. GAAP requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as cash flows from operating activities. When excess tax benefits are used to reduce income taxes payable, the benefits are 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:
The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the three months ended March 31, 2018:
PNMR’s stock-based compensation program provides for performance and market targets through 2020. Included as granted and as exercised in the above table are 97,697 previously awarded shares that were earned for the 2015 through 2017 performance measurement period and ratified by the Board in February 2018 (based upon achieving market targets at “target” levels, weighted at 60%, and performance targets at below “target” levels, weighted at 40%). Excluded from the above table are maximums of 134,219, 155,291, and 152,750 shares for the three-year performance periods ending in 2018, 2019, and 2020 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible. 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 met specific performance targets at the end of 2016 and 2017 and he remained an employee of the Company. If PNMR achieved the specified 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. Similarly, if PNMR achieved the specified performance target for the period from January 1, 2015 through December 31, 2017, he was 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. In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she was to receive 17,953 of the total shares if PNMR achieved 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 the restricted stock shares that remain unvested under this retention award agreement. At March 31, 2018, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $2.5 million with a weighted-average remaining contract life of 1.8 years. At March 31, 2018, no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date. The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options:
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Financing |
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Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financing | 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 contains a single financial covenant, which requires the maintenance of a debt-to-capital 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. 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 2017 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 has a maturity of February 1, 2021 and bears interest at a rate based on LIBOR plus a customary spread, which aggregated 4.41% at March 31, 2018. 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 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 requires that NM Capital utilize all amounts, less taxes and fees, it receives under the Westmoreland Loan to repay the BTMU Term Loan Agreement. The principal balance outstanding under the BTMU Term Loan Agreement was $45.1 million at March 31, 2018. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $10.0 million on the BTMU Term Loan Agreement in the twelve months ended March 31, 2019. 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). On July 28, 2017, PNM entered into an agreement (the “PNM 2017 Senior Unsecured Note Agreement”) with institutional investors for the sale of $450.0 million aggregate principal amount of Senior Unsecured Notes (the “PNM 2018 SUNs”) offered in private placement transactions. Under 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 include customary covenants, including a covenant that requires the maintenance of a debt-to-capital 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 million under PNM’s Senior Unsecured Notes due on May 15, 2018 and August 1, 2018, are reflected as being long-term in the Condensed Consolidated Balance Sheet at March 31, 2018 since the PNM 2017 Senior Unsecured Note Agreement demonstrates PNM’s ability and intent to re-finance the aggregate $450.0 million Senior Unsecured Notes 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:
On March 9, 2018, PNMR issued $300.0 million aggregate principal amount of 3.250% Senior Unsecured Notes (the “PNMR 2018 SUNs”), which mature on March 9, 2021. The proceeds from the offering were used to repay the $150.0 million PNMR 2015 Term Loan Agreement, and to reduce borrowings under the PNMR Revolving Credit Facility. At March 31, 2018, variable interest rates were 2.64% on the $100.0 million PNMR 2016 Two-Year Term Loan, which matures in December 2018, and 2.61% on the $200.0 million PNM 2017 Term Loan Agreement, which matures in January 2019. Short-term Debt and Liquidity Currently, the PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. PNMR and PNM have entered into agreements to extend the maturities of both facilities to October 31, 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, 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 and matures on September 23, 2022. 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 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:
At March 31, 2018, the weighted average interest rate was 3.05% for the PNMR Revolving Credit Facility, 2.54% for the TNMP Revolving Credit Facility, 2.72% for the PNMR Development Revolving Credit Facility, and 2.63% for the PNMR 2016 One-Year Term Loan (as extended), which matures in December 2018. In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $6.4 million, $2.5 million, and $0.1 million at March 31, 2018 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of March 31, 2018 and December 31, 2017, PNM had $54.6 million and zero and TNMP had $2.6 million and zero of intercompany borrowings from PNMR. On April 9, 2018, PNMR Development deposited $68.2 million with PNM related to transmission network interconnection studies. PNM used the deposit to repay intercompany borrowings. 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 $3.1 million at March 31, 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 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 April 23, 2018, PNMR, PNM, TNMP, and PNMR Development had availability of $197.4 million, $397.5 million, $34.5 million, and none under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $40.0 million of availability under the PNM New Mexico Credit Facility. Total availability at April 23, 2018, on a consolidated basis, was $669.4 million for PNMR. As of April 23, 2018, PNM and TNMP had no borrowings from PNMR under their intercompany loan agreements. At April 23, 2018, PNMR, PNM, and TNMP had invested cash of $0.9 million, $8.6 million, and none. As described above, PNM entered into the PNM 2017 Senior Unsecured Note Agreement on July 28, 2017 to issue $450.0 million of the PNM 2018 SUNs on May 15, 2018 and August 1, 2018, proceeds from which will be used to repay like amounts of PNM Senior Unsecured Notes maturing on those dates. The $200.0 million PNM 2017 Term Loan Agreement matures on January 18, 2019. PNM has no other long-term debt due through March 31, 2019. The $100.0 million PNMR 2016 One-Year Term Loan (as extended) matures on December 14, 2018 and the $100.0 million PNMR 2016 Two-Year Term Loan matures on December 21, 2018. PNMR also anticipates repayments on the BTMU Term Loan Agreement of $10.0 million in the period from April 1, 2018 through March 31, 2019 and $9.4 million in the remainder of 2019. TNMP has $172.3 million of first mortgage bonds that are due in April 2019. The $24.5 million PNMR Development revolving credit facility expires on February 25, 2019. Additional information on debt maturities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. |
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Retirement Benefits [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans | Pension and Other Postretirement Benefit Plans PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans. 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 2017 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. In March 2017, the FASB 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 Company presented 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. 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 for the three months ended March 31, 2017 reflect a reclassification of 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, net of amounts capitalized prior to the adoption of the standard. 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 months ended March 31, 2018, PNM recorded $0.9 million of non-service cost as Other deductions, which is net of $0.3 million deferred as regulatory assets, and TNMP recorded $0.1 million of non-service cost to Other income, which is net of less than $0.1 million deferred as regulatory liabilities. PNM Plans The following table presents the components of the PNM Plans’ net periodic benefit cost:
PNM did not make any contributions to its pension plan trust in the three months ended March 31, 2018 and 2017 and does not anticipate making any contributions to the pension plan in 2018-2021, but expects to contribute $5.1 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 4.0% to 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 months ended March 31, 2018 and 2017. PNM does not expect to make any contributions to the OPEB trust in 2018-2022. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.5 million and $0.5 million in the three months ended March 31, 2018 and 2017 and are expected to total $1.5 million during 2018 and $5.7 million for 2019-2022. TNMP Plans The following table presents the components of the TNMP Plans’ net periodic benefit cost:
TNMP did not make any contributions to its pension plan trust in the three months ended March 31, 2018 and 2017 and does not anticipate making any contributions in 2018-2022, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.0% to 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 $0.3 million and $0.7 million to the OPEB trust in the three months ended March 31, 2018 and 2017. TNMP expects to make no additional contributions to the OPEB trust in 2018 and $1.4 million for 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 months ended March 31, 2018 and 2017 and are expected to total $0.1 million during 2018 and $0.4 million in 2019-2022. |
Commitments and Contingencies |
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||
Commitments and Contingencies | Commitments and Contingencies Overview There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 12) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows. With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. The Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, 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 2017 Annual Reports on Form 10-K. Commitments and Contingencies Related to the Environment Nuclear Spent Fuel and Waste Disposal Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the 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 March 31, 2018 and December 31, 2017, PNM had a liability for interim storage costs of $12.2 million and $12.3 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 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 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 cannot predict if there will be challenges to this action or the potential outcome of such challenges. The Clean Air Act Regional Haze In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress by adopting a new SIP every ten years. In the first SIP planning period, 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 was demonstrated that the emissions from these sources caused or contributed to visibility impairment in any Class I area, then BART must have 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. EPA also provided a companion draft guidance document for public comment. The new rule delayed the due date for the next cycle of SIPs from 2019 to 2021, 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. EPA’s new rule was challenged by numerous parties. On January 19, 2018, EPA filed a motion to hold the case in abeyance in light of several letters issued by EPA on January 17, 2018 to grant various petitions for reconsideration of the 2017 rule revisions. On January 30, 2018, the court placed the case in abeyance and directed EPA to 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 evaluating the potential impacts of this 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 2017 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”) on SJGS Units 1 and 4 was completed in early 2016 and Units 2 and 3 were retired in 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”). See Note 12 for information concerning the NMPRC’s treatment of BDT in PNM’s NM 2015 Rate Case. The December 2015 NMPRC order also provided, among other things, that:
NEE filed a notice of appeal with the NM Supreme Court of the NMPRC’s December 2015 order 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. The parties presented oral argument to the court on January 25, 2017. On 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 filed by the statutory deadline. This matter is now 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 (see Coal Supply below). 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. 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. The NMPRC has taken no action on these matters. 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 2017 Annual Reports on Form 10-K, SJGS was 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 plan to comply with EPA regional haze rules at SJGS, 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. On July 31, 2015, the SJGS participants executed the San Juan Project Restructuring Agreement (“SJGS RA”). 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. The SJGS 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. 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 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. 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 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 is anticipated to be completed in May 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 $89.0 million, including amounts incurred through March 31, 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 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 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. EPA indicated it has not determined whether it will promulgate a new rule under section 111(d) or what form a new rule would take. Comments to EPA’s new rule were due by February 26, 2018. 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 May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO2 NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO2 sources to identify maximum 1-hour SO2 concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO2 sources through ambient monitoring or modeling. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO2 NAAQS. On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposes deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO2 emissions. The settlement results from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree requires the following: (1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; (2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule. SJGS and Four Corners SO2 emissions are below the 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. In July of each year, NMED will submit an annual report to EPA documenting annual SO2 emissions from SJGS and the associated compliance status. 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 should 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 October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 parts per billion (“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. 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. 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 November 6, 2017, EPA released a final rule establishing some, but not all, initial area designations. In that final rule, EPA designated 2,646 counties (representing about 85% of the counties in the United States) as attainment/unclassifiable, and three counties in Washington as unclassifiable. San Juan County, New Mexico, where SJGS and Four Corners are located, is designated as attainment/unclassifiable. On December 21, 2017, EPA issued a notice of availability of its intended designations for the remaining undesignated areas. EPA stated that it intended to address the remaining areas in a separate future action, but did not specify a time frame for doing so. Under the CAA, EPA was required to promulgate area designations no later than October 1, 2017. The notice announces the availability of “120-day letters,” which were sent directly to states and tribes on December 20, 2017, and contain EPA’s intended air quality designations for the remaining areas. The only county in New Mexico designated as non-attainment is Dona Ana County. States and tribes were required to provide EPA any additional information they would like EPA to consider by February 28, 2018. EPA intends to make final designations for all areas addressed in the 120-day letters no later than April 30, 2018. In a related matter, EPA published a final rule on March 9, 2018 that establishes air quality thresholds, which 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 becomes 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 United States District Court for the District of New Mexico. 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 is expected to be available for public comment in mid-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 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. 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. The requirements related to Four Corners will be addressed in a subsequent NPDES permitting cycle that will determine APS’s costs to comply with the rule. PNM does not expect such costs to be material. Effluent Limitation Guidelines On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants. EPA’s proposal 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 must be incorporated into plants’ NPDES permits. Each plant must comply between 2018 and 2023 depending on when it needs a new/revised NPDES permit. 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 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 certain waste streams. 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 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. Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. Until a draft NPDES permit is proposed for Four Corners, APS is uncertain what will be required to comply with the revised effluent limitations during the revised compliance timeframe (from November 1, 2020 through December 31, 2023). PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. Santa Fe Generating Station PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well. The Superfund Oversight Section of the NMED 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. 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. Under the next phase, 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. Work commenced in March 2018. 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. In June 2010, EPA published a proposed rule that included two options for waste designation of coal ash. One option was to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option was to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. On December 19, 2014, EPA issued its coal ash rule, which included a non-hazardous waste determination for coal ash. Coal ash will be regulated as a solid waste under Subtitle D of RCRA. The rule sets minimum criteria for existing and new CCB landfills and existing and new CCB surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria; groundwater monitoring and corrective action; closure requirements and post closure care; and recordkeeping, notification, and internet posting requirements. Because the rule is promulgated under Subtitle D, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non-compliance with the new requirements. EPA published the final CCB rule in the Federal Register on April 17, 2015, 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 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 January 2019. Depending upon the results of such groundwater monitoring and data evaluations, Four Corners may be required to take corrective actions, the costs of which 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 was not required to take final action approving the inclusion of boron, but EPA was required to consider its inclusion. In March 2018, EPA issued a proposed rule amending the CCB rule, which proposes, among other things, to add boron to the list of constituents that trigger corrective action. 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 if the EPA will ultimately amend the CCB rule or the eventual impacts of those amendments. 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 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. 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. 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. 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 March 31, 2018 and December 31, 2017, prepayments for coal (including amounts purchased from the existing 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. 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, 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 SJGS CSA. 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 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 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 $45.1 million at March 31, 2018. 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 was 9.25% plus LIBOR for the period from February 1, 2017 through January 31, 2018 and is 12.25% plus LIBOR for the period from February 1, 2018 through January 31, 2019. 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 March 31, 2018, the amount outstanding under the Westmoreland Loan was $51.0 million. The next principal payment of $0.9 million plus interest of $1.8 million is due on May 1, 2018. As of April 23, 2018, $2.7 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. On March 28, 2018, NM Capital executed an extension and waiver agreement with WSJ, which waived a technical event of default by WSJ under the Westmoreland Loan. This waiver related to the required delivery of the financial statements of WSJ’s parent company and expires on the earlier of May 1, 2019 or the occurrence of any other event of default. See Note 6. 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 purchases all of Four Corners’ coal requirements from NTEC, an entity owned by the Navajo Nation, under a coal supply contract (the “Four Corners CSA”) that expires in 2031. The coal comes from reserves located within the Navajo Nation. NTEC has contracted with Bisti Fuels Company, LLC, a subsidiary of The North American Coal Corporation, for management and operation of the mine. The average coal price per ton 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, excluding the disputed amounts discussed below. The contract provides for pricing adjustments over its term based on economic indices. PNM’s share of the costs is being recovered through the 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 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. On September 20, 2017, NTEC amended its demand for arbitration removing the request for a declaratory judgment. PNM’s share of the total estimated alleged shortfall through March 31, 2018 is estimated to be $11.6 million. An arbitration regarding the alleged shortfall in the first contract year is scheduled for May 21, 2018. PNM anticipates that substantially all of any amount it ultimately is required to pay would be collected through the FPPAC. Although PNM cannot predict the timing or outcome of the arbitration, the outcome is not expected to have a material impact on its financial position, results of operations, or cash flows. Coal Mine Reclamation As 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 shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA, the SJGS participants requested that the coal mine reclamation study for SJGS be updated as of December 31, 2016. That reclamation cost estimate reflects the terms of the new reclamation services agreement with Westmoreland and continuation of mining operations through 2053, as well as the anticipated impacts of the shutdown of SGS Units 2 and 3 on December 31, 2017. 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 March 31, 2018 for mine reclamation, in future dollars, are estimated to be $99.7 million for the surface mines at both SJGS and Four Corners and $127.1 million for the underground mine at SJGS. At March 31, 2018 and December 31, 2017, liabilities, in current dollars, of $41.2 million and $41.4 million for surface mine reclamation and $15.1 million and $14.7 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. 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. If the NMPRC orders 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 an increase in the amount of fill dirt required to remediate the mine areas, thereby increasing the overall reclamation costs. PNM would record an additional amount when it is determined that the increase to the liability is probable and can be reasonably estimated, which would be dependent on receiving 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. As part of the restructuring of SJGS ownership (see SJGS Ownership Restructuring Matters above), the SJGS owners 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 March 31, 2018, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $7.5 million in 2018, $8.7 million in 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 2017 and anticipates providing additional funding of $2.3 million in each of 2018 and 2019. 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. 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 provision of the settlement agreement. 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 $13.2 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 $12.7 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. 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 endorsement by the parties and the New Mexico 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. San Juan River Adjudication In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, then 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 entered its appearance in the appellate case. On April 3, 2018, the New Mexico Court of Appeals issued an order affirming the decision of the New Mexico District Court. Several parties filed motions requesting a rehearing with the New Mexico Court of Appeals seeking clarification of the order. 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 and 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 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 County filed a motion for judgment on one of the utilities’ claims, which was granted by the court, leaving a claim regarding telecommunications service as the remaining federal claim. 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 proceed in New Mexico District Court. The utilities and Bernalillo County reached a standstill agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement. If the challenges to the ordinance are unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations. Navajo Nation Allottee Matters A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both. In March 2010, the court ordered that the entirety of the plaintiffs’ case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court. In May 2010, plaintiffs filed a notice of appeal with the Bureau of Indian Affairs (“BIA”), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director’s decision to the DOI, Office of Hearings and Appeals, Interior Board of Indian Appeals. Following briefing on the merits, on August 20, 2013, that board issued a decision upholding the Regional Director’s decision that the allottees had failed to perfect their appeals, and dismissed the allottees’ appeals, without prejudice. The allottees have not refiled their appeals. Although this matter was dismissed without prejudice, PNM considers the matter concluded. However, PNM continues to monitor this matter in order to preserve its interests regarding any PNM-acquired rights-of-way. In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice. On April 2, 2014, the allottees’ appeal was dismissed with prejudice. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments. On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested. The letter indicated that the renewals were not approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. On July 13, 2015, PNM filed a condemnation action in the NM District Court 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 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. 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. 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, which was denied. The NM District Court has stayed the case until May 15, 2018 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 December 22, 2017, amicus briefs supporting PNM’s Petition for Writ of Certiorari were filed with the US Supreme Court. On March 23, 2018, responses to PNM’s petition were filed. On April 5, PNM filed its reply brief in support of its Petition for Writ of Certiorari. PNM cannot predict the outcome of these matters. 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. |
Regulatory and Rate Matters |
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Regulatory and Rate Matters | Regulatory and Rate Matters The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2017 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. 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. 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 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, 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:
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. 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 the 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 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. 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. On September 28, 2016, the NMPRC issued an order 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:
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, PNM’s statement indicated it is appealing the following elements of the NMPRC’s order:
The issues that are being appealed by the various cross-appellants include:
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 was 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 a loss 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 indicated 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. As of September 30, 2016, PNM estimated it would 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 would remain in effect. PNM concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case; that the minimum amount of loss was 15 months of capital cost recovery that 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 was a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million at September 30, 2016 for the capital costs that will not be covered during that 15 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 could no longer assert that those assets were probable of being recovered through the ratemaking process. 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 was recorded in 2016 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. 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 that it will take seven months from December 31, 2017 for the NM Supreme Court to issue a decision and any remanded issues to be addressed by the NMPRC. Accordingly, PNM recorded an additional loss of $3.1 million at December 31, 2017, representing an additional disallowance of seven months of capital cost recovery that the order disallowed. Further losses will be recorded if the currently estimated time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is extended. PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudent and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is 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 recognized in future 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 March 31, 2018, such losses could include:
Although PNM does not believe that the likelihood of the cross-appeals being successful is probable, 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 $150.4 million (which amount includes $75.3 million that is the subject of PNM’s appeal discussed above) at March 31, 2018, after considering the losses recorded in 2016 and 2017. 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 were:
The NMPRC scheduled a public hearing to begin on June 5, 2017, ordered that a settlement conference 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, after which the date for filing a stipulation was extended. 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. NEE was the sole party opposing the revised stipulation. The terms of the revised stipulation, which required NMPRC approval in order to take effect, included:
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 significant changes to the revised stipulation in the Hearing Examiners’ Modified Revised Stipulation included:
On December 20, 2017, the NMPRC issued an Order 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 Argument asking 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:
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 All Signatories of Acceptance of the Order on Notice of Acceptance. 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 required PNM to recognize a loss to reflect that PNM will not earn an equity return on $148.1 million of investments at Four Corners. As of December 31, 2017, PNM recorded a pre-tax regulatory disallowance of $27.9 million. The amount of the loss was calculated by determining the present value of disallowed cash flows, which equals the difference between the cash flows resulting from recovery of those investments at PNM’s embedded cost of debt and the cash flows with a full return on investment (including an equity component), and discounting the differences at PNM’s WACC. 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. 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 be 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 several public workshops have been held. PNM cannot predict the outcome of this proceeding. 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:
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 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, and continuation of customer REC purchase programs and other purchases of RECs to ensure annual compliance with the RPS. PNM’s proposed procurement cost for 2018 and 2019 will be within the RCT. The plan also sought a variance from the “other” diversity category in 2018 due to a revised production forecast of the Lightning Dock Geothermal facility in 2018. 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 PNM be required to issue another all-renewables RFP allowing developers to utilize PNM-owned sites to construct facilities, the output from which facilities would be sold to PNM through PPAs. PNM strongly disagreed with the Hearing Examiner’s recommendations and filed exceptions contesting the Hearing Examiner’s proposals. On November 15, 2017, the NMPRC issued an order approving PNM’s plan and rejecting the Hearing Examiner’s recommendations. On November 29, 2017, NMIEC filed an appeal with the NM Supreme Court objecting to the fuel 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 and PNM filed a response opposing the request. On February 27, 2018, the court issued an order denying the motion for stay. On April 9, 2018, NMIEC filed its Brief in Chief. Answer briefs are due on May 29, 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 basis. In PNM’s NM 2015 Rate Case, the NMPRC authorized continuation of the renewable rider. In its 2018 renewable energy procurement plan case, PNM proposed to collect $43.5 million for the year. The 2018 renewable energy procurement plan became effective on January 1, 2018. PNM recorded revenues from the rider of $10.9 million and $12.2 million in the three months ended March 31, 2018 and 2017. 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 2017. Energy Efficiency and Load Management Program Costs and Incentives/Disincentives The 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 EUEA 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 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 is subject to NMPRC approval. PNM expects the NMPRC will rule on this matter by mid-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 sought approval of a sliding scale incentive with a base incentive of $1.9 million if PNM is able to achieve savings 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, 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. On 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 the tax-adjusted WACC of 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. 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. 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 for approval of energy efficiency and load management programs should be filed every two years rather than annually. On June 21, 2017, the NMPRC issued an order that modifies the filing frequency for utility energy efficiency plans to every three years. Also on June 21, 2017, the NMPRC 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. 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. 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 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 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 responded 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 a 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 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:
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 assigned the case to a Hearing Examiner. On January 16, 2018, the Hearing Examiner issued an order setting the scope of the 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 are scheduled to begin on June 4, 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. 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 promptly contacted the staff of the NMPRC to inform them of the event and has initiated a review of its cause. PNM currently anticipates inspections of the facility and a determination of estimated repair costs will be completed by the end of May 2018 and that the unit will be returned to service shortly after that date. PNM anticipates the damages to the facility will be reimbursed 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 requests 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. On 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 must also address the necessity and appropriateness of the request for a cost/benefit analysis, alternatives assessment, and request for further proceedings. 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 asked 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, the costs of customer education, and severances for affected employees. 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, PNM requested a new procedural schedule to allow it 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 had not proven 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 the recommended decision indicating, among other things, that PNM disagreed with the finding 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 adopted an order accepting the recommended decision and disapproving PNM’s application. The order indicated PNM’s next energy efficiency plan filing should include a proposal for an AMI pilot project. Facebook, Inc. Data Center Project As 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 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:
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 was to be through a PPA with PNMR Development for the energy production from 30 MW of new solar capacity that PNMR Development was to construct. As discussed in Note 1, PNMR Development transferred its interests in the solar capacity and the PPA to NMRD in December 2017. The cost of the PPA is passed through to Facebook under a new rate rider. The new special service rate is applied to Facebook’s energy consumption in those hours of the month when their consumption exceeds the energy production from the renewable resources. The first 10 MW of solar capacity began commercial operation on January 1, 2018, the second 10 MW began commercial operation in March 2018, and the remaining capacity is anticipated to be completed by mid-2018. 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 Facebook. These PPAs were subject to NMPRC approval and PNM made a filing requesting approval on January 17, 2018. A NMPRC hearing on PNM’s filing was held on March 7, 2018 and the NMPRC approved the PPAs on March 21, 2018. These PPAs include the purchase of the power and RECs from:
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. In connection with TNMP’s deployment of AMS, TNMP committed to file a general rate case no later than September 1, 2018. TNMP will include a reconciliation of AMS costs in the 2018 filing. 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 April 23, 2018, 98 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. Transmission Cost of Service Rates TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s recent interim transmission cost rate increases:
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 advanced 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 2018 general rate case. Order Related to Changes in Federal Income Tax Rates On January 25, 2018, the PUCT issued an accounting order that addresses the change in federal 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 income tax rate. In addition, 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. As discussed in Note 11 of the Notes to the Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K, at December 31, 2017, TNMP recorded a regulatory liability for deferred income taxes of $146.5 million to reflect the change in federal income tax rates that will be refunded to customers in future periods. In compliance with the PUCT order, during the three months ended March 31, 2018, TNMP recorded a regulatory liability of $1.5 million, which amount represents the impact of the reduction in the federal corporate income tax rate on revenues collected from January 25, 2018 through March 31, 2018. The order provides that these regulatory liabilities will be considered by the PUCT in each utility’s next rate proceeding, which for TNMP is anticipated to be filed in May 2018. TNMP is evaluating whether the PUCT order constitutes retroactive ratemaking and whether to advocate such a position in future rate proceedings. TNMP cannot predict the outcome of this matter. |
Lease Commitments |
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Mar. 31, 2018 | |
Leases [Abstract] | |
Lease Commitments | 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 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 March 31, 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. |
Income Taxes |
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Mar. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 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 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 income taxes as a reduction to customer rates over a twenty-one year period beginning in 2018. In January 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 months ended March 31, 2018, TNMP recorded a regulatory liability of $1.5 million in accordance with the PUCT’s order (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 March 31, 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 that assumption. In addition, the portion of the adjustment that was not related to PNM’s regulated activities was recorded 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 resulted in refinements of the impacts of this change in tax rates being recorded periodically through December 31, 2017, at which time the impacts of the rate reduction were fully phased in. In the three months ended March 31, 2017, PNM’s regulatory liability was reduced by $4.8 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities 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. The benefit of the lower New Mexico corporate income tax rate is being returned to customers over a three-year period beginning February 1, 2018 as ordered in PNM’s NM 2016 Rate Case. As required under GAAP, the Company 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 applying 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 March 31, 2018, PNMR, PNM, and TNMP estimated their effective income tax rates for the year ended December 31, 2018 would be 12.11%, 8.07%, and 23.47%. These rates reflect the reduced federal corporate income tax rate of 21%, which rates are adjusted to reflect permanent differences between earnings determined in accordance with GAAP and taxable income, as well as state income taxes. The primary permanent difference is the reduction in income tax expense resulting from the amortization of excess deferred federal and state income taxes ordered by the NMPRC in PNM’s NM 2016 Rate Case. During the three months ended March 31, 2018, income tax expense calculated by applying the expected annual effective income tax rate to earnings before income taxes for PNMR, PNM, and TNMP was further reduced by excess tax benefits related to stock awards of $1.3 million, $1.0 million and $0.3 million. |
Related Party Transactions |
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Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions | Related Party Transactions PNMR, PNM, TNMP, and NMRD 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. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD:
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Significant Accounting Policies and Responsibility for Financial Statements (Policies) |
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Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates Valencia (Note 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. 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 (Note 15). All intercompany transactions and balances have been eliminated. |
New Accounting Pronouncements | 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 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, 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. At adoption, ASU 2016-02 requires that leases be recognized and measured as of the earliest period presented using a modified retrospective approach with all periods presented being restated and presented under the new guidance. 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 2017 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. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. 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. The Company has formed a project team, conducted outreach activities across its lines of business, and made significant progress in identifying arrangements that may be classified as leases under ASU 2016-02 in addition to its existing operating lease arrangements. 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 arrangement 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 throughout 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. 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 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 effective as of January 1, 2020, its required effective date, although early adoption is permitted beginning on January 1, 2019. The Company 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 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 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 2017-12 – 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. As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 2017 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 2017 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. GAAP requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as cash flows from operating activities. |
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. |
Segment Information (Tables) |
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Summary of Financial Information by Segment | The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. PNMR SEGMENT INFORMATION
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Accumulated Other Comprehensive Income (Loss) (Tables) |
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accumulated Other Comprehensive Income (Loss) | Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2018 and 2017 is as follows:
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Earnings Per Share (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Computation of Earnings Per Share | Information regarding the computation of earnings per share is as follows:
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Electric Operating Revenues (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue from Contract with Customer [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disaggregation of Revenue | A disaggregation of revenues from Contracts with customers for the three months ended March 31, 2018 by the type of customer is presented in the table below. The table also reflects ARP revenues and Other revenues.
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Schedule of changes in balances of contract liabilities | 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:
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Variable Interest Entities (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summarized Financial Information | Summarized financial information for Valencia is as follows: Results of Operations
Financial Position
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Fair Value of Derivative and Other Financial Instruments (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of 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:
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Effect of Mark-to-Market on Earnings, Excluding Tax Effects | 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.
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Schedule of Net Buy (Sell) Volume Positions | The table below presents PNM’s net buy (sell) volume positions:
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Schedule of Fair Value and Gross Unrealized Gains in Available-for-sale Securities | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Gross Realized Gains and Losses | 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.
The proceeds and gross realized gains and losses on the disposition of 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 ($1.2) million and $1.1 million for the three months ended March 31, 2018 and 2017.
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Investments Classified by Contractual Maturity Date | At March 31, 2018, the available-for-sale and held-to-maturity debt securities had the following final maturities:
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Schedule of Investments |
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||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Level 3 Measurements | A reconciliation of the changes in Level 3 fair value measurements is as follows:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Carrying Amount and Fair Value of Items Not Recorded at Fair Value | 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:
|
Stock-Based Compensation (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Activity | The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options:
The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:
The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the three months ended March 31, 2018:
|
Financing (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of maturities and interest rates | Information concerning the maturities and interest rates on the PNM 2018 SUNs to be issued in May 2018 and August 2018 is as follows:
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Schedule of Short-term Debt | Short-term debt outstanding consisted of:
|
Pension and Other Postretirement Benefit Plans (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement Benefits [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Net Benefit Costs | The following table presents the components of the TNMP Plans’ net periodic benefit cost:
The following table presents the components of the PNM Plans’ net periodic benefit cost:
|
Regulatory and Rate Matters (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulated Operations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Rate Increases for Transmission Costs | The following sets forth TNMP’s recent interim transmission cost rate increases:
|
Related Party Transactions (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Related Party Transactions | The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD:
|
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Earnings Per Share [Abstract] | ||
Net Earnings Attributable to PNMR | $ 14,990 | $ 22,862 |
Average Number of Common Shares: | ||
Outstanding during period (in shares) | 79,654 | 79,654 |
Vested awards of restricted stock (in shares) | 205 | 112 |
Average Shares – Basic (in shares) | 79,859 | 79,766 |
Dilutive Effect of Common Stock Equivalents: | ||
Stock options and restricted stock (in shares) | 154 | 346 |
Average Shares – Diluted (in shares) | 80,013 | 80,112 |
Net Earnings Per Share of Common Stock: | ||
Basic (in dollars per share) | $ 0.19 | $ 0.29 |
Diluted (in dollars per share) | $ 0.19 | $ 0.29 |
Electric Operating Revenues - Narrative (Details) $ in Thousands |
3 Months Ended | |||
---|---|---|---|---|
Mar. 31, 2017
USD ($)
|
Mar. 31, 2018
USD ($)
|
Dec. 31, 2017
USD ($)
|
Dec. 16, 2015
MW
|
|
PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Alternative revenue programs | $ 1,100 | |||
Other electric operating revenue | 28,400 | |||
TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Alternative revenue programs | 3,500 | |||
Other electric operating revenue | $ 0 | |||
Customer contracts | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Accounts receivable | $ 58,700 | $ 62,900 | ||
Clean Air Act, SNCR | Palo Verde Nuclear Generating Station Unit 3 | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Number of megawatts nuclear generation (in megawatts) | MW | 134 |
Electric Operating Revenues - Changes in contract liabilities (Details) $ in Thousands |
3 Months Ended |
---|---|
Mar. 31, 2018
USD ($)
| |
Change In Contract With Customer Liability [Roll Forward] | |
Beginning balance | $ 349 |
Consideration received in advance of service to be provided | 5,495 |
Deferred revenue earned | (1,477) |
Ending balance | 4,367 |
PNM | |
Change In Contract With Customer Liability [Roll Forward] | |
Beginning balance | 349 |
Consideration received in advance of service to be provided | 3,983 |
Deferred revenue earned | (1,099) |
Ending balance | 3,233 |
TNMP | |
Change In Contract With Customer Liability [Roll Forward] | |
Beginning balance | 0 |
Consideration received in advance of service to be provided | 1,512 |
Deferred revenue earned | (378) |
Ending balance | $ 1,134 |
Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - PNM - Designated as Hedging Instrument - Commodity derivatives - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Derivative Instruments, Gain (Loss) [Line Items] | ||
Total gain | $ 2 | $ 3,352 |
Electric operating revenues | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Total gain | (10) | 3,341 |
Cost of energy | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Total gain | $ 12 | $ 11 |
Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) - PNM |
3 Months Ended | 12 Months Ended | |
---|---|---|---|
Mar. 31, 2018
USD ($)
MWh
MMBTU
|
Dec. 31, 2016
MWh
MMBTU
|
Dec. 31, 2017
USD ($)
|
|
Derivative [Line Items] | |||
Net exposure | $ | $ 0 | $ 0 | |
Commodity derivatives | Fair value hedging | Buy | |||
Derivative [Line Items] | |||
Economic Hedges (in mmbtu and mwh) | MMBTU | 405,000 | 100,000 | |
Commodity derivatives | Fair value hedging | Sell | |||
Derivative [Line Items] | |||
Economic Hedges (in mmbtu and mwh) | MWh | 40,800 | 0 |
Fair Value of Derivative and Other Financial Instruments - Investments in NDT (Details) $ in Thousands |
3 Months Ended |
---|---|
Mar. 31, 2018
USD ($)
| |
Equity securities: | |
Net gains from equity securities sold | $ 2,828 |
Net gains from equity securities still held | 136 |
Total net gains on equity securities | 2,964 |
Available-for-sale debt securities: | |
Net gains (losses) on debt securities | (2,676) |
Net gains on investment securities | $ 288 |
Fair Value of Derivative and Other Financial Instruments - Maturities of Debt Securities (Details) $ in Thousands |
Mar. 31, 2018
USD ($)
|
---|---|
Held-to-Maturity | |
Within 1 year | $ 0 |
After 1 year through 5 years | 57,486 |
After 5 years through 10 years | 0 |
After 10 years through 15 years | 0 |
After 15 years through 20 years | 0 |
After 20 years | 0 |
Held-to-maturity debt securities | 57,486 |
PNMR and PNM | |
Available-for-Sale | |
Within 1 year | 8,562 |
After 1 year through 5 years | 53,094 |
After 5 years through 10 years | 66,603 |
After 10 years through 15 years | 9,735 |
After 15 years through 20 years | 10,061 |
After 20 years | 36,263 |
Available-for-sale debt securities | $ 184,318 |
Fair Value of Derivative and Other Financial Instruments - Reconciliation of changes in Level 3 fair value measurements (Details) - Corporate Debt - Level 3 $ in Thousands |
3 Months Ended |
---|---|
Mar. 31, 2018
USD ($)
| |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Beginning balance | $ 0 |
Actual return on assets sold during the period | (3) |
Actual return on assets still held at period end | (11) |
Purchases | 2,724 |
Sales | (359) |
Ending balance | $ 2,351 |
Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - PNM - Nuclear spent fuel and waste disposal - Palo Verde Nuclear Generating Station - USD ($) |
May 16, 2014 |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|---|
Public Utilities, Commitments And Contingencies [Line Items] | |||
Estimate of possible loss | $ 57,700,000 | ||
Revised annual fee, nuclear waste disposal | $ 0 | ||
Other deferred credits | |||
Public Utilities, Commitments And Contingencies [Line Items] | |||
Loss contingency accrual | $ 12,200,000 | $ 12,300,000 |
Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - TNMP - USD ($) $ in Millions |
Mar. 27, 2018 |
Sep. 13, 2017 |
Mar. 14, 2017 |
Sep. 08, 2016 |
Mar. 23, 2016 |
---|---|---|---|---|---|
Transmission Cost of Service Rates | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Approved Increase in Rate Base | $ 30.2 | $ 9.5 | $ 25.8 | ||
Annual Increase in Revenue | $ 4.8 | $ 1.8 | $ 4.3 | ||
PUCT | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Requested rate increase (decrease) | $ 32.0 | $ 27.5 | |||
Proposed increase (decrease) in revenues | $ 0.6 | $ 4.7 |
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